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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, January 18, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Adam Earl
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
I-32
MILNE PT UNIT I-32
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 01/18/2024
I-32
50-029-23759-00-00
223-054-0
W
SPT
3905
2230540 1500
155 156 156 156
INITAL P
Adam Earl
12/4/2023
Initial MIT-IA/ mono-bore
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT I-32
Inspection Date:
Tubing
OA
Packer Depth
741 2203 2161 2148IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitAGE231206101354
BBL Pumped:2.1 BBL Returned:2.1
Thursday, January 18, 2024 Page 1 of 1
By Grace Christianson at 3:41 pm, Nov 30, 2023
Complete
10/2/2023
JSB
RBDMS JSB 121223
G
DSR-1/29/24
Drilling Manager
11/30/23
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 10/12/2022
SCHEMATIC
Milne Point Unit
Well: MPU I-32
Last Completed: 10/2/23
PTD: 223-054
5-1/2” x 4-1/2” Slotted Liner
Size Top (MD)
Top (TVD)Btm (MD) Btm (TVD)
5-1/2”7094’ 3927’ 9923’ 3978’
4-1/2” 10295’ 3949’ 19790’ 4182’
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 152’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,341’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,341’ 7,179’ 0.0758
5-1/2” Slotted Liner 17 / L-80 / JFE Bear 4.892” 6,896’ 9,965’ 0.0232
4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 9,965’ 19,831’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surface 6,920’ 0.0087
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4"Stg 1 –Lead 669 sx / Tail 400 sx
Stg 2 –Lead 736 sx / Tail 270 sx
8-1/2” Uncemented Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: 50-029-23759-00-00
Completion Date: 10/2/23
WELL INCLINATION DETAIL
KOP @ 519’
90° Hole Angle = 8,007’ MD
TD =19,831’(MD) / TD =4,182’(TVD)
20”
Orig. KB Elev.:67.49’/ GL Elev.:33.2’
3-1/2”
4/5
7
2
9-5/8”
1
3
See
Slotted
Liner
Detail
PBTD =19,829’(MD) / PBTD =4,182’(TVD)
9-5/8” ‘ES’
Cementer @
2,356’
5-1/2” x
4-1/2”
@9965’
6
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 6,090’ Viking Sliding Sleeve (Opens down) 2.870”
2 6,143’ Zenith Gauge Carrier 2.992”
3 6,199’ XN Nipple, 2.813”, 2.75” No-Go 2.840”
4 6,909’ Locater Sub, 8.28” No Go (bottom of locator spaced out 2.06’) 6.170”
5 6,910’ Bullet Seals – TXP Top Box x Mule Shoe 6.170”
Lower Completion
6 6,896’ 9-5/8” SLZXP Liner Top Packer (11.27’ tieback sleeve) 6.180”
7 19,829’ Shoe
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU I-32 Date:9/21/2023
Csg Size/Wt/Grade:9.625", 40# x 47#, L-80 Supervisor:Anderson / Toomey
Csg Setting Depth:7179 TMD 3932 TVD
Mud Weight:9.3 ppg LOT / FIT Press =553 psi
LOT / FIT =12.00 Hole Depth =7237 md
Fluid Pumped=1.10 Bbls Volume Back =1.00 bbls
Estimated Pump Output:0.101 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->142 ->4 176
->2 129 ->8 386
->3 187 ->12 590
->4 245 ->16 762
->5 292 ->20 944
->6 333 ->24 1150
->7 380 ->28 1350
->8 433 ->32 1539
->9 475 ->36 1756
->10 519 ->40 1983
->11 557 ->44 2182
->12 ->48 2430
->14 ->53 2719
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 557 ->0 2719
->1 525 ->5 2698
->2 520 ->10 2693
->3 517 ->15 2689
->4 515 ->20 2686
->5 513 ->25 2682
->6 510 ->26 2682
->7 508 ->27 2682
->8 506 ->28 2681
->9 505 ->29 2680
->10 503 ->30 2680
->11 501 ->
->12 500 ->
->13 499 ->
->14 497
->15 496
->16 495
0
1
2
3
4
5 6
7
8
9
1011
0
4
8
12
16
20
24
28
32
36
40
44
48
53
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0102030405060
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
557525520517515513510508506505503501500499497496495
2719 2698 2693 2689 2686 268226822682268126802680
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
9/8/2023 Lay mats around and in front of I-32. Finish installing choke and kill lines, move rig to north side of pad, remove BOP stack from cradle, secure stack on pedestal in
cellar. Set diverter bag and tee on conductor along with staging WH equipment. finish matting in front of I-32. Submit 24hr diverter test notification to AOGCC. Spot
and shim rig PJSM. Spot the rig and center over well I-32. Shim and level the rig. Lower the stairs and install the handrails. PJSM, Prep rig floor, breaking down
steam manifold. Skid floor into drilling position. Prep pipeshed for drillpipe and orient diverter tee in prep for nipple up. W ork on rig acceptance checklist. R/U
service lines to the rig floor. Prepping mud pits for drilling ops. Spot auxiliary shacks and pump house. N/U knife valve. Install first 3 joints of diverter line. Spot the
cuttings tank, fuel trailer and start spotting the rock washer.
9/9/2023 Continue to load pipe shed with drill pipe, continue to NU diverter and install riser, spot rock washer, work on ST-80 base assembly. IT RU coms to Sperry and MI
shacks. Work on rig acceptance checklist. Put rig on hiline power @ 10:15 hrs. Spot rock washer into drill position, install snorkel extensions on front rock washer
for SS access. install riser and torque bolts, load shed with 230 jts 5'' DP, 17 jts HWDP and the BHA. Continue installing diverter line. Mechanic Work on C/O
bearing on brake water cooling fan for dyno-matic. Spot upright water tanks and plumb lines for same, set cement silos in place. Work on rig acceptance checklist:
Fill pit 5 with water, no leaks, circulate water through lines in all pits. Welder fixing broken gunline swivel in Pit #3, patching cracked wall between pit 3&4 and
cracked wall in trip tank. Install SS extensions on Rockwasher. Install cellar pump & manifold. Remove a link from #1 conveyor. Install 90' mousehole. Repaired a
bearing on skate carriage, hose reel assembly. Welder finish fixing gunline swivel in pit #3. Slip and cut 80' drilling line. Inspect mud pits for welding debris/tools.
Service Topdrive / Calibrate block height. Mobilize drilling subs, floor valves, BHA components & geo-span to rig floor. Move H2O to pit #4 and inspect for leaks.
9/10/2023 Mobilize subs, XOs, FOSV, dart valve, bits, BHA tools and geo skid to the rig floor, perform derrick inspection, welder start repairs on broken gunline in pit 3.
Continue working on acceptance checklist. PJSM, PU and rack 6 stands HWDP in the derrick includes jar stand,. SimOps: Welder repairing gun line in pit 3.
Perform the diverter function test with 5" HWDP. The test witness waived by AOGCC inspector Adam Earl via email on 9/9/23 at 18:57 hours. Knife valve opened in
17 seconds and the annular closed in 35 seconds. Test gas alarms - good. Accumulator Test: System pressure = 3,050 psi. Pressure after closure = 1,800 psi. 200
psi attained in 26 seconds. Full pressure attained in 144 seconds. N2 Bottles avg - 6 at 1,880 psi. Diverter length = 226'. Nearest ignition source = 102' (light on
sperry shack). Welder continue to repair gun line in pit 3, load hardline to rig floor and cellar, test run pump house. Install 100 mesh screens on shakers, calibrate
the newly installed top drive anti collision system. Work on acceptance checklist. PJSM, MU BHA 1, 12 1/4'' tricone bit, 1.5 deg mud motor and XO, MU stand
HWDP TD. Flood stack and lines with fresh water, test mud line from IBOP to mud pumps, good. 2 welders continue repairing gun line section in pit 3. Prime pump,
flood stack & lines w/ fresh H2O, attempt to test the geo span & mud line from IBOP to mud pumps, lost hi line power @ 16:30 - Ground fault on shore side -, put rig
on gen power @ 16:45,. Test mud line & geo span to 3000 psi, good, bleed off pressure. Back on hi line @ 17:45. Mobilize new gun line section to pit 3, welders
install same and patch newly identified cracks in pits #1 & 3 walls. Test gun line. Connection leaking at new line in pit #3 and leak found on gun line in pit #4.
Welders repair both leaks. Put H2O in pit #2 and observe leak on ODS outer wall. Empty pit to inspect and locate leak. Call out second welder to aid in repairs.
Grind and weld suspect spots in pit #2. Finish gunline repairs and put fresh water in pit #2. Observe ODS wall still leaking. Contact pad operator to discuss hot-work
permit so the outer wall can be cut out and the source of the leak identified.
9/11/2023 Continue with pit repairs, welder remove 2' x 2' section outer wall pit #2, identify and repair leaks on same. Weld leaks along mud cleaner suction line in pit #2,. Fill
pit #2 with water and hold 20 min, leaking around mud cleaner suction box, empty pit, repair from inside of pit #2, fill pit #2 with water,. Continue to test pit #2, no
leaks, transfer and fill pit #1 with water, leaking on mid wall on cellar side, empty pit, welder repair wall, fill with water, no leaks, remove water from from pits leaving
78 bbls in pit #4. Acceptance checklist completed, accept rig @ 15:30 hrs. Remove water from from pits leaving 78 bbls in pit 4. Take on 580 bbls 8.8 ppg spud
mud to pits. Test PVT and flow alarms. Conduct rig evacuation drill and muster at primary point. Hold pre-spud meeting with all parties involved. Discussed well
objectives and surface hole hazards. Table top diverter drill. RIH with stand and tag up @ 50' MD. Flood system with water. Riser connection leaking on top of
annular preventer. Tighten bolts. Engage pumps and rotary cleanout conductor to 127'. Swap to spud mud on the fly & #2 MP stroke counter broke. Proceed with
#1 MP at 230 gpm, 120 psi, 30 rpm, 1k tq, 1-2k WOB. Flow line packed off with pea gravel and sand shortly after spud mud returns. Repair #2 pump stroke counter
while cleaning gravel from flow line and drip pan. Adjust line-up for flow-line jets, to obtain more flow/pressure. Finish clean out conductor to 152' and drill 12-1/4"
surface hole to 220'. 402 GPM, 460 PSI, 30 RPM, 1K ft/lbs Tq, 2K WOB. 52K PU / 51K SO / 52K ROT. 8.8 ppg MW, 214 vis. Pump out of hole f/ 220' t/ 127' then
pull out on elevators to surface. Inspect bit - No damage, cones rotate freely. Change out the tri-cone bit with a 12-1/4" Kymera and RIH with motor. M/U Gyro While
Drilling, MWD directional, gamma and resistivity tools to 99'. Test and initialize MWD tools. P/U 3 NM flex collar to 193'. Perform shallow pulse test, 400 GPM, 850
psi.
9/12/2023 Drill 12-1/4" surface hole from 220' to 468' (468' TVD). Drilled 248' = 62'/hr AROP. 400 GPM = 840 psi, 40 RPM = 1K ft-lbs TQ, WOB = 2-10K. MW = 9.1 ppg, Vis
= 300+,. PU = 70K, SO = 73K, ROT = 70K. Start 3 deg/100' build at 450'. MP #2 traction motor overheating while on SCR #4, swap assignment putting SCR #4 on
drawworks as per electrician, drawworks traction motor operating erratic. Decision made to TOOH to conductor and troubleshoot SCR #4. Fill the trip tank, with well
static TOOH on elevators from 468' to 99' racking HWDP and flex collars in derrick. 2.5 bbl losses. While parked in conductor Electrician remove SCR panel and
troubleshoot SCR #4 . Monitor well with trip tank. Electrician found blown fuses in SCR #4, troubleshoot same, DDI electrical supervisor on location to assist
electrician. Replace fuses and inspect wiring, energize SCR #4, blackout the rig @ 14:20. Troubleshooting electrical issues. Replace fuses again and other wiring
before closing hi line breaker at 21:00, instantly blowing fuses in SCR #4 again. Pull SCR #4 and put Rig on Gen power with no SCRs, for lighting and basic
operations. Plan to continue troubleshooting in AM. Totco rep on location- troubleshoot block height not tracking on totco screen, faulty encoder, source another
from Deadhorse. Perform general housekeeping and processing 9-5/8" casing. Monitor Well via trip tank. No losses.
9/13/2023 Electricians continue troubleshooting SCR 4 electrical issues. Source parts from Deadhorse. Changeout damaged wiring and fuse blocks in SCR 4. SimOps:
Perform general housekeeping and processing 9-5/8" casing, Changeout some conveyor paddles. Monitor Well via trip tank. No losses. Continue to work on SCR
4. Finish changing out fuse blocks, fuses and replacing damaged wiring. Put the rig in the dark at 12:45 hours. Tie in new fuse blocks. Perform low amp 600v test -
good. Put rig on gen power at 13:40 hours. Test SCRs 1-4 on all assignments - good. Contact Hilcorp hi-line, Put rig on hi-line at 16:45 hours. Test SCRs 1-4 on hi
line power through all assignments - good. TIH with NMFC and HWDP to 411'. Obtain parameters and tool face with MWD. Wash to bottom at 468' with no fill
observed. Drill 12-1/4" surface hole from 468' to 749' (744' TVD). Drilled 281' = 56.2'/hr AROP. 400 GPM = 990 psi, 40 RPM = 1K ft-lbs TQ, WOB = 5K. PU = 78K,
SO = 82K & ROT = 73K. MW = 9.1 ppg, Vis = 180, ECD = 9.76 ppg. Start 4 deg/100' build at 500'. Rig on generator power at 20:25 hours due to MP turbine
maintenance. Drill 12-1/4" surface hole from 749' to 1,415' (1,345' TVD). Drilled 666' = 111'/hr AROP. 444 GPM = 1,400 psi, 60 RPM = 5-6K ft-lbs TQ, WOB = 8K.
PU = 96K, SO = 90K & ROT = 92K. MW = 9.1+ ppg, Vis = 185, ECD = 10.5 ppg, max gas = 1 units. Start 4.5 deg/100' build at 1,181'. First good MWD survey at
1,262'. Distance from WP10 at survey depth of 1,181.9 = 18.13 (7.13 low & 16.67 left).
9/11/2023Spud Date:
Well Name:
Field:
County/State:
MP I-32
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23759-00-00API #:
9/14/2023 Drill 12-1/4" surface hole from 1,415' to 1,887' (1,670' TVD). Drilled 472' = 118'/hr AROP. 444 GPM = 1,460 psi, 60 RPM = 6K ft-lbs TQ, WOB = 7K. PU = 102K,
SO = 90K & ROT = 95K. MW = 9.3 ppg, Vis = 153, ECD = 10.49 ppg, max gas = 31 units. Build and turn 4.5 deg/100'. Conveyor #1 chain came off the sprocket,
back on at 10:50 hours. Run new cable for block height encoder and attempt to calibrate but unable to get it to calibrate. Drill 12-1/4" surface hole from 1,887' to
2,350' (1,902' TVD). Drilled 463' = 92.6'/hr AROP. 450 GPM = 1,430 psi, 60 RPM = 5-6K ft-lbs TQ, WOB = 2-3K. PU = 105K, SO = 81K & ROT = 93K. MW = 9.4
ppg, Vis = 92, ECD = 10.19 ppg, max gas = 57 units. Begin 62 deg tangent section at 2,019'. Troubleshoot encoder software while drilling. Values is software were
wrong. Downloaded correct values. Recalibrate encoder on connection. Calibration successful. Rig back on hi-line at 16:30 hours. Drill 12-1/4" surface hole from
2,350' to 2,936' (2,162' TVD). Drilled 586' = 97.7'/hr AROP. 450 GPM = 1,430 psi, RPM = 5-7K ft-lbs TQ, WOB = 4-6K. PU = 109K, SO = 85K & ROT = 95K. MW
= 9.4+ ppg, Vis = 100, ECD = 10.56 ppg, max gas = 546 units. Base of permafrost logged at 2,429' (1,931' TVD). Pumped 30 bbl hi-vis sweep at 2,553', did not
observe at surface. Drill 12-1/4" surface hole from 2,936' to 3,697' (2,525' TVD). Drilled 761' = 126.8'/hr AROP. 500 GPM = 1,760 psi, 80 RPM = 8K ft-lbs TQ,
WOB = 4-15K. PU = 125K, SO = 90K & ROT = 105K. MW = 9.4+ ppg, Vis = 61, ECD = 10.2 ppg, max gas = 131 units. Begin drop to 61 deg and turn to 282 deg
at 3,410'. Distance from WP10 at survey depth of 3,357.09 = 12.73 (6.17 high & 11.13 right).
9/15/2023 Drill 12-1/4" surface hole from 3,697' to 4,363' (2857' TVD). Drilled 666' = 111'/hr AROP. 500 GPM = 1,760 psi, 80 RPM = 8K ft-lbs TQ, WOB = 4-15K. PU = 125K,
SO = 90K & ROT = 105K. MW = 9.4 ppg, Vis = 61, ECD = 10.2 ppg, max gas = 131 units. Pump 30 bbl hi-vis sweep at 3,983', back 200 strokes early with 100%
increase. Drill 12-1/4" surface hole from 4,363' to 5,026' (3,173' TVD). Drilled 663' = 110.5'/hr AROP. 532 GPM = 2,090 psi, 60 RPM = 10-12K ft-lbs TQ, WOB = 5-
7K. PU = 152K, SO = 92K & ROT = 115K. MW = 9.3+ ppg, Vis = 80, ECD = 10.24 ppg, max gas = 57 units. Drill 12-1/4" surface hole from 5,026' to 5,667' (3,486'
TVD). Drilled 641' = 106.8'/hr AROP. 540 GPM = 2,110 psi, 60 RPM = 11-15K ft-lbs TQ, WOB = 6-9K. PU = 168K, SO = 94K & ROT = 124K. MW = 9.3+ ppg, Vis
= 55, ECD = 9.88 ppg, max gas = 183 units. Pump 30 bbl hi-vis sweep at 5,026', back on time with 50% increase. Drill 12-1/4" surface hole from 5,667' to 6,115'
(3,695' TVD). Drilled 448' = 74.7'/hr AROP. 477 GPM = 1,800 psi, 60 RPM = 13-17K ft-lbs TQ, WOB = 5-10K. PU = 192K, SO = 90K & ROT = 130K. MW = 9.2
ppg, Vis = 50, ECD = 9.9 ppg, max gas = 3,228 units. At 5,898' had an increase in gas and the shakers blinded off. Slowed the pumps down to 500, 450 then 400
GPM and reduced ROP. During the connection screened down the shakers. Begin 4.5 deg/100' build and turn at 5,980'. Distance from WP10 at survey depth of
5,924.37 = 14.14 (12.91 high & 5.77 right).
9/16/2023 Drill 12-1/4" surface hole from 6,115' to 6,590' (3,848' TVD). Drilled 457' = 79'/hr AROP. 550 GPM = 2,410 psi, 60 RPM = 17K ft-lbs TQ, WOB = 18K. PU = 193K,
SO = 92K & ROT = 127K. MW = 9.3 ppg, Vis = 54, ECD = 10.1 ppg, max gas = 543 units. Pump 30 bbl hi-vis sweep at 6,083' back on time with 20% increase.
Drill 12-1/4" surface hole from 6,590' to TD at 7,217' (3,934' TVD). Drilled 627' = 89.57'/hr AROP. 548 GPM = 2,270 psi, 60 RPM = 15K ft-lbs TQ, WOB = 4-5K.
PU = 182K, SO = 88K & ROT = 123K. MW = 9.4 ppg, Vis = 50, ECD = 10.22 ppg, max gas = 459 units. Encountered fault A at 6,697' with a 40' DTN throw. Obtain
final MWD survey at TD. Distance from WP10 at survey depth of 7,217' = 9.82' (9.81' high & 0.26' left). Pump 30 bbl hi-vis sweep and circulate the hole clean at
550 GPM = 2,150 psi, 60 RPM = 15K ft-lbs TQ while reciprocating 90' alternating stopping points. Sweep back on time with 20% increase. Continue to circulate 2
BU racking back a stand each BU. MW in/out = 9.2+/9.3+ ppg & Vis in/out = 47/80. TIH to TD. BROOH from 7,217' to 6,835' pulling 5-10 minutes/stand slowing as
needed to clean up slides/tight spots. 550 GPM = 2,030 psi, 60 RPM = 15-17K ft-bs TQ, ECD= 9.79 ppg, max gas = 7 units. PU = 185K, SO = 85K, ROT = 124K.
BROOH from 6,835' to 4,361' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 550 GPM = 1,850
psi, 60 RPM = 11K ft-bs TQ, ECD= 10.11 ppg, max gas = 72 units. PU = 190K, SO = 85K, ROT = 110K.
9/17/2023 BROOH from 4,361' to 1,605' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,570 psi, 60 RPM = 6-9K ft-bs TQ, ECD=
10.33 ppg, max gas = 152 units. PU = 115K, SO = 83K, ROT = 93K. BROOH from 1,605' to 750' pulling 5-10 minutes/stand slowing as needed to clean up
slides/tight spots. 550 GPM = 1,470 psi, 60 RPM = 1-3K ft-bs TQ, ECD= 10.17 ppg, max gas = 32 units. PU = 86K, SO = 86K, ROT = 85K. Circulate 2 BU while
BROOH last stand of DP at 550 GPM = 1,470 psi, 60 RPM = 1-3K ft-bs TQ. Lost 46 bbls while BROOH. Flow check well - static. TOOH on elevators from 750' to
193' racking back 6 stands HWDP with jars in derrick. PJSM. LD 3 NM flex collars from 193' to 99'. Plug in and download MWD data. Lay down remaining BHA
from 99' to surface. 12-1/4"" Kymera Dull Bit Grade: PDC = 1-1-CT-N-X-I-WT-TD & Cones = 1-1-NO-A-E-I-NO-TD. Clean and clear the rig floor. Flush the flow line
and blow down the cement line. PJSM. Mobilize casing running equipment to rig floor. Make up Volant CRT, bail extensions, elevators, spiders and tongs. Make up
crossover to FOSV. Verify pipe counts and tally. Static loss rate = 3 BPH. PJSM with rig crew, DDI Casing and Halliburton Cementing. MU 9-5/8", 40#, L80, BTC
shoe track to the diamond. Baker-lok first 3 connections and add centralizers per tally. Fill the casing and check floats - holding. Install bypass baffle on top of float
collar. MU the baffle adapter to 166'. RIH with 9-5/8", 40#, L-80, BTC casing from 166' to 2,365' installing centralizers per tally. TQ = 11K ft-lbs with Volant tool. Fill
on the fly and top off every 10 joints. PU = 135K & SO = 85K. Circulate BU while RIH from 2,365' to 2,444' at 5 BPM = 150 psi.
9/18/2023 Continue to RIH with 9-5/8", 40#, L-80, BTC casing from 2,440' to 4,604' installing centralizers per tally. TQ = 11K ft-lbs with Volant tool. Fill on the fly and top off
every 10 joints. PU = 253K & SO = 105K. Continue to RIH with 9-5/8", 40#, L-80, BTC casing from 4,604' to 4,811' installing centralizers per tally. TQ = 11K ft-lbs
with Volant tool. Fill on the fly and top off every 10 joints. PU = 270K & SO = 102K. Loss rate = 0.5 BPH, Max gas = 5 units. PU and MU ES Cementer. Halliburton
cementers double checked shear screws (6 screws 3,300 psi). Continue to RIH with 9-5/8", 47#, L-80, BTC casing from 4,811' to tag at TD of 7,217' installing
centralizers per tally. TQ = 9K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. PU = 340K & SO = 105K. LD joints #22 and #23 due to a galled box
and pin. Swapped out with joints #62 and #63. Lost 57.5 bbls while running casing. LD tag joint. Galled the box and pin. Changeout the collar and MU the space out
short joint. Stage the pumps up to 6 BPM = 330 psi (ICP). Circulate and condition the mud while reciprocating 30'. FCP = 150 psi. MW = 9.4 ppg, Vis = 42 & YP =
6. PU = 320K & SO = 125K. SimOps. Cementer spotted in and RU. Prep the mud pits for cement job. RD spiders, power tongs, elevators and bail extensions. Shut
down the pumps. Blow down the top drive. Redope the cup and reengage the Volant CRT. RU the cement line to the Volant. PJSM with all parties involved while
continuing to circulate. Continue to circulate. Mix Desco, SAPP and Bicarb in the last 50 bbls pumped. Shut down the pumps. HES flood line with fresh water and
break circulation with 5 bbls. Attempt to PT lines but had a couple high pressure line connection leak. Tighten up connections. PT lines to 1,000/4,000 psi - good
test. Pump 1st stage cement job: . Mix & pump 60 bbls of 10 ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 5 BPM = 335 psi. Drop bypass
plug. Mix and pump 280 bbls of 12.0 ppg lead cement (EconoCem, Type I/II, 2.347ft^3/sk yield, 669 sks total) at 7.5 BPM = 715 psi. Mix and pump 82 bbls of 15.8
ppg tail cement (HalChem type 1-2 cement, 1.155 ft^3/sk yield, 400 sks total) at 4 BPM = 555 psi. Drop shut off plug. HES pump 20 bbls water at 7 BPM = 489 psi.
Displace with 327 bbls of 9.4 ppg spud mud from the rig at 7 BPM = 200 psi. Pumped 80 bbls of 9.4 ppg tuned spacer from Halliburton at 5 BPM = 660 psi.
9/19/2023 Continue to displace with 9.4 ppg spud mud at 7 BPM = 810 psi. Slowed rate to 3 BPM = 690 psi ICP & 750 psi FCP for the last 10 bbls. Bumped the plugs 10
strokes (1 bbl) early. CIP at 06:18 hours. Pressure up to 1,300 psi and hold for 3 min. Bleed pressure to 0 psi. Check floats - floats holding. Pressure up to 2,840 psi
shifting the ES cementer open. Lost 21 bbls during the job. At 3,231 strokes into displacing while reciprocating pipe, the pipe became stuck. Unable to work up or
down past 7,178' but still had full circulation. Park with string in tension. Circulate through the ES cementer at 2,358' at 6 BPM = 320 psi ICP & psi 164 psi FCP.
Dump 30 bbls cement, 60 bbls spacer and 106 bbls interface. Begin taking returns to the pits. Circulate a total of 5 BU. Shut down the pumps. Disconnect hydraulic
lines from bag and knife valve. Flush the stack and surface equipment 3 times with blackwater. Re-connect hydraulic lines and breakout volante. LD 27' short joint
of 9 5/8'' casing. Re-dope cup and MU Volant. Continue to circulate through the ES cementer at 6 BPM = 220 psi while waiting for the cement to reach 500 psi
compressive strength. Prepare for the 2nd stage cement job. Hold PJSM with all parties involved. Continue to circulate while changing out the cement pump truck
and prime up. Blow air through the cement line to the cement unit. Shut down the pumps. HES flood line with fresh water and break circulation with 5 bbls. PT lines
to 1,000/4,000 psi - good test. Pump 2nd stage cement job: . Mix & pump 60 bbls of 10.0 ppg Tuned Spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 3
BPM = 151 psi. Mix & pump total 377.5 bbls 10.7 ppg ArcticCem lead cement (736 sx at 2.855 ft^3/sk yield) at 6.5 BPM = 561 psi (ICP) & 690 psi (FCP). Mix &
pump 56 bbls of 15.8 ppg HalCem tail cement (270 sx at 1.165 ft^3/sk yield) at 3 BPM= 489 psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh at 4 BPM =
181 psi. Displace cement with 9.4 ppg spud mud. 6 BPM = 225 psi (ICP) & 710 psi (FCP). Slowed to 4 BPM = 600 psi for last 10 bbls. Bumped plugs at 1,498
strokes (1.9 bbls early). Pressured up and shifted the ES cementer closed at 1,470 psi. Continue to pressure up to 1,850 psi and hold for 2 minutes. Bleed pressure
to 0 psi and check for flow - none. CIP at 22:50 hours. No losses during the job. Returns to surface: 60 bbls of spacer, 95 bbls interface and 233 bbls of cement.
Blow down the lines. Disconnect the knife valve from the accumulator. Drain the stack and flush with blackwater 3 times. RD the Volant CRT. Vacuum out the mud
from the casing. RU the 9-5/8" elevators. ND the knife valve. BOLDS on the speed head. Let the air out of the air boots on the riser. Lift the surface annular.
SimOps: ND diverter line. Install the casing slips with 100K on the slips. SimOps: ND diverter line. Cut the 9-5/8"" casing and lay down. Cut joint = 3.21'. SimOps:
ND diverter line. Pull the riser. ND the surface annular. Pull the mouse hole. Remove 4" conductor valves and install caps. ND diverter tee. SimOps: Demobilize
casing equipment from the rig floor.
9/20/2023 ND the diverter tee and remove from the cellar. Mobilize the wellhead into the cellar. Install slip-loc wellhead. PT the void to 500 psi for 5 minutes and 3,800 psi for
10 minutes - good test. NU adapter spool, spacer spool and the BOP stack. SimOps: Clean the pits. RD and move cement silos. NU the MPD Orbit valve. Attempt to
turn the RCD head but unable to. NU the kill and choke lines. Torque all the BOP stack bolts. SimOps: Mobilize testing equipment. Changeout sprocket on #1 drag
chain. Connect all the Koomey hoses to the BOP stack and energize the Koomey unit. Install the MPD riser and air up the air boots. RU BOPE testing equipment.
Flood the BOP stack, lines and choke manifold with fresh water. Attempt shell test but Koomey hydraulic hose leaking. Tighten up. Pressure up and choke line
Oteco clamp leaking. Tighten up. Shell test the BOP stack to 250/3,000 psi (passed). Conduct initial BOPE test to 250/3,000 psi: UPR & LPR (2-7/8 x 5 VBRs) with
3-1/2 & 5 test joints, annular with 3-1/2 test joint, accumulator drawdown test and test gas alarms. All tests performed with fresh water against test plug. The test was
witnessed by AOGCC inspector Josh Hunt. Tests:. 1.Annular with 3-1/2 test joint, 3 Demco kill, choke valves 1, 12, 13 & 14 (passed). 2.UPR with 3-1/2 test
joint, HCR kill, choke valves 9 & 11 (passed). 3.Manual kill, 5 TIW, choke valves 5, 8 & 10 (passed). 4.5 dart valve, choke valves 4, 6 & 7 (passed). 5.Upper
IBOP, Choke valve 2 (passed). 6.Lower IBOP, HCR choke (passed). 7.LPR with 3-1/2 test joint (passed). 8.UPR with 5 test joint, manual choke (passed).
9.LPR with 5 test joint (passed). 10.Blind rams, choke valve 3 (passed). 11.Manual adjustable choke (passed). 12.Hydraulic super choke (passed).
Accumulator Test:. System pressure = 3,050 psi. Pressure after closure = 1,600 psi. 200 psi attained in 41 seconds. Full pressure attained in 196 seconds.
Nitrogen Bottles - 6 at 1,825 psi. Control System Response Time:. Annular = 19 seconds. UPR, Blind Rams & LPR = 9 seconds. HCR Choke & Kill = 2 seconds.
Pull the test plug and install the wear ring (ID = 9-1/8"). Blow down and RD testing equipment. PJSM. MU 8-1/2" Cleanout BHA: 8-1/2" tricone bit, 6-3/4" mud motor
with non-ported float installed in top and ABH set at 1.5 deg. Open the blind rams and the BOPE control panel is indicating the blinds are both open and closed.
Troubleshoot. Call out rig electrician to troubleshoot.
9/21/2023 Replace faulty pressure switch in Koomey control panel and re-install control cover. TIH from surface to 2,299' just above ES cementer. Wash down to 2,356'. Drill
cement, plug and ES cementer to 2,359'at 380 GPM = 660 psi, 40 RPM = 3-7K ft-lbs TQ, WOB = 3-6K. Work through 2x with pumps and rotation and 1x without
with no issues. Continue to wash and ream down to 2,395' chasing debris. TIH from 2,395' to 6,965' on stands out of the derrick. PU = 200K & SO = 75K. Wash
down from 6,965' and tag hard cement at 7,017' at 100 GPM = 800 psi, 20 RPM = 22K ft-lbs TQ. CBU to condition mud for casing PT at 350 GPM = 940 psi, 20
RPM = 22K ft-lbs TQ. MW 9.4 ppg in/out. RU testing equipment and purge air from the system. Close the UPR and PT the 9-5/8" casing to 2,500 psi for 30 minutes
charted - good test. Pumped 5.3 bbls to pressure up and bled back 5.3 bbls. Blow down and rig down test equipment. Drill cement and float equipment from 7,017'
to 7,179'. Drill rathole and 20' of new formation to 7,237' at 400 GPM = 1,140 psi, 30 RPM = 148K ft-lbs TQ, WOB = 5-14K. PU = 193K, SO = 130K & ROT = 119K.
Rack back 1 stand to 7,153'. Circulate and condition mud prior to performing FIT at 500 GPM = 1,551 psi, 40 RPM = 21K ft-lbs TQ, reciprocating string 60'. RU
testing equipment and purge air from the system Close the UPR. Perform FIT to 12.0 ppg with 9.3 ppg MW at 3,932' TVD and applying 553 psi at surface. Good
test. Pumped 1.1 bbls and bled back 1 bbl. Blow down and rig down test equipment. Pump dry job for trip out. TOOH from 7,153' to 588'. Lost 10.5 bbls while
TOOH. Monitor the well for flow - static. Lay down 15 joints of HWDP and rack back jar stand. Lay down cleanout BHA. Bit grade: 1-1-WT-A-E-1-NO-BHA. Clear
and clean the rig floor. Pull the master bushings and install the split bushings. PJSM. MU 8-1/2" PDC bit, bit sleeve, Geo-Pilot, ADR, ILS, DGR, PWD, directional &
telemetry collars and IBS to 90'. Plug in and initialize MWD. MU remaining BHA #4, NM float sub, NM flex collars, NM float sub, NM flex collars and 2 HWDP with
jars to 278'. TIH from 278' to 368'. Shallow pulse test MWD and break in the geo-pilot seals. Continue to TIH to 753'.
9/22/2023 Continue to TIH from 753' to 6,935'. PU = 230K & SO = 70K. PJSM. Finish install the MPD drip pan. Drain the riser. Pull the MPD riser and install the MPD RCD
bearing. Install the RCD head skirt for the drip pan. Fill the DP and break circulation. Check for leaks - none. Single in the hole with 5" DP from the pipe shed from
6,935' to 7,157'. PJSM. Pump pit #4 empty. Pump 30 bbl spacer pill. Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro NT at 6 BPM = 720 psi (ICP), 120
RPM = 19K ft-lbs TQ. Wash to TD with mud at the bit then pull into the casing. Reciprocate 30'. Good mud to surface at 6 BPM = 550 psi (FCP), 120 RPM = 11K ft-
lbs TQ, PU = 145K & SO = 100K. Dump spacer & 62 bbls of interface. Shut in and monitor for pressure build with MPD - none. PJSM. Slip and cut 59' (9 wraps) of
drilling line. Service the top drive. SimOps: Clean pit 4 and surface equipment. Obtain SPR's and wash down to 7,237'. Drill 8-1/2" lateral from 7,237' to 7,983'
(3,964' TVD). Drilled 746' = 99.5'/hr AROP. 500 GPM = 1,790 psi, 120 RPM = 14K ft-lbs TQ, WOB = 10-15K. PU = 150K, SO = 88K & ROT = 112K. MW = 9.0
ppg, Vis = 47, ECD = 10.65 ppg, max gas = 674 units. Undulate down at 87 deg through the OA-1 exiting at 7,440' into the OA-2. Encountered fault #1 at 7,497'
with 35' DTN throw moving the wellbore from the OA-2 to the NF clays. Reacquired the OA-1 sand at 7,750'. Continue to undulate down exiting the OA-1 at 7,880'
and entering the OA-3 at 7,913'. Drill 8-1/2" lateral from 7,983' to 8,709' (3,983' TVD). Drilled 726' = 121'/hr AROP. 540 GPM = 2,010 psi, 120 RPM = 11K ft-lbs
TQ, WOB = 10K. PU = 145K, SO = 87K & ROT = 112K. MW = 9.0 ppg, Vis = 42, ECD = 10.9 ppg, max gas = 709 units. Level out in the OA-3 at 90 deg. Exited the
OA-3 at 8,096' into the OA-4. Begin undulating down at 8,266' in preparation for upcoming fault crossing. Exited the OA sand at 8,296' into the Schrader Bluff shale.
Targeting 85 deg. Encountered fault #2 at 8,596' with 72' DTN throw moving the wellbore from the SB shale to OA-1. Pump 30 bbl hi-vis sweep at 8,459', back on
time with 100% increase. Drilled 11 concretions for a total thickness of 116 (8.5% of the lateral). Distance from WP10 at survey depth of 8,292.67 = 18.97 (18.24
low & 5.19 left).
9/23/2023 Drill 8-1/2" lateral from 8,709' to 9,476' (4,001' TVD). Drilled 767' = 127.8'/hr AROP. 532 GPM = 2,120 psi, 120 RPM = 8K ft-lbs TQ, WOB = 13-15K. PU = 145K,
SO = 85K & ROT = 106K. MW = 9.1 ppg, Vis = 40, ECD = 11.0 ppg, max gas = 900 units. MPD choke full open while drilling & trapping 9.3 EMW on connections.
Drill down through the OA-1 exiting at 8,800'. Encountered fault #3 at 8,932' with 15' DTN throw moving the wellbore from the OA-2 to the NF clays. Reentered the
OA-1 at 9,095'. Encountered fault #4 at 9,454' with 32' DTS throw moving the wellbore from the OA-1 to the SB shale. Drill 8-1/2" lateral from 9,476' to 10,172'
(3,963' TVD). Drilled 696' = 116'/hr AROP. 430 GPM = 1,600 psi, 120 RPM = 11K ft-lbs TQ, WOB = 13-15K. PU = 142K, SO = 82K & ROT = 108K. MW = 8.9
ppg, Vis = 41, ECD = 10.9 ppg, max gas = 571 units. MPD choke full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at
9,580', back on time with 100% increase. Perform 290 bbl dump and dilute at 9,980'. Reentered the OA-3 at 9,781'. Encountered fault #5 at 9,918' with 47' DTS
throw moving the wellbore from the OA-3 to the SB shale. Drill 8-1/2" lateral from 10,172' to 10,744' (3,938' TVD). Drilled 572' = 95.3'/hr AROP. 525 GPM = 2,190
psi, 120 RPM = 11K ft-lbs TQ, WOB = 13-16K. PU = 150K, SO = 80K & ROT = 108K. MW = 9.1 ppg, Vis = 41, ECD = 11.3 ppg, max gas = 409 units. MPD choke
full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at 10,362', back on time with 100% increase. Reentered the OA-3 at
10,245'. Continue drilling up to avoid close approach of J-26. Exited the OA-3 at 10,380' entered the OA-1 at 10,10,430'. At 10,460' begin dropping, targeting 87
deg at 4 deg/100'. Control drilled at 100'/hr ROP and reduced RPM to 80 while drilling past J-26. Drill 8-1/2" lateral from 10,744' to 11,696' (3,999' TVD). Drilled ' =
'/hr AROP. 523 GPM = 2,150 psi, 120 RPM = 12K ft-lbs TQ, WOB = 10-12K. PU = 155K, SO = 73K & ROT = 107K. MW = 9.1 ppg, Vis = 41, ECD = 11.16 ppg,
max gas = 728 units. MPD choke full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at 11,315', back on time with 100%
increase. Exit the OA-1 at 970' and entered the OA-3 at 11,156'. Drilled 26 concretions for a total thickness of 195 (4.5% of the lateral). Distance from WP10 at
survey depth of 11,339.42 = 6.19 (2.57 high & 5.63 left).
9/24/2023 Drill 8-1/2" lateral from 11,696' to 12,550' (4,008' TVD). Drilled 854' = 142.3'/hr AROP. 520 GPM = 2,150 psi, 120 RPM = 14K ft-lbs TQ, WOB = 15K. PU = 155K,
SO = 65K & ROT = 105K. MW = 8.9 ppg, Vis = 40, ECD = 11.27 ppg, max gas = 671 units. MPD choke full open while drilling and trapping 9.3 EMW on
connections. Perform 430 bbl dump and dilute at 11,750'. Undulate up, exiting the OA-3 at 11,778', entering the OA-1 at 12,040' and level out. Drill 8-1/2" lateral
from 12,550' to 13,409' (' TVD). Drilled 859' = 143.2'/hr AROP. 536 GPM = 2,250 psi, 120 RPM = 13K ft-lbs TQ, WOB = 6-12K. PU = 170K, SO = 53K & ROT =
107K. MW = 9.2 ppg, Vis = 38, ECD = 11.5 ppg, max gas = 745 units. MPD choke full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-
vis sweep at 12,931', back on time with 200% increase. Perform 580 bbl dump and dilute at 13,314'. Drill 8-1/2" lateral from 13,409' to 14,172' (4,047' TVD). Drilled
763' = 127.2'/hr AROP. 532 GPM = 2,210 psi, 120 RPM = 14K ft-lbs TQ, WOB = 14K. PU = 170K, SO = 52K & ROT = 107K. MW = 9.1 ppg, Vis = 38, ECD = 11.3
ppg, max gas = 609 units. MPD choke full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at 13,695', back on time with 100%
increase. Begin undulation down at 13,500', exiting the OA-1 at 13,650', entering the OA-3 at 13,730' and level out. Drill 8-1/2" lateral from 14,172' to 14,743' ('
TVD). Drilled 571' = 95.2'/hr AROP. 536 GPM = 2,250 psi, 120 RPM = 16K ft-lbs TQ, WOB = 10-15K. PU = 170 K, SO = 0K & ROT = 105K. MW = 9.0+ ppg, Vis =
40, ECD = ppg, max gas = 635 units. MPD choke full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at 14,265', back on time
with 50% increase. Lost down weight at 14,360'. Begin undulation up at 14,615'. Drilled 40 concretions for a total thickness of 286' (3.9% of the lateral). Distance
from WP10 at survey depth of 145,385.34' = 2.69' (1.23' high & 2.39' right).
9/25/2023 Drill 8-1/2" lateral from 14,743' to 15,407' (4,054' TVD). Drilled 727' = 121.2'/hr AROP. 498 GPM = 2,110 psi, 120 RPM = 17K ft-lbs TQ, WOB = 10-20K. PU =
170K, SO = 0K & ROT = 106K. MW = 9.0 ppg, Vis = 40, ECD = 11.26 ppg, max gas = 759 units. MPD choke full open while drilling and trapping 9.3 EMW on
connections. Pump 30 bbl hi-vis sweep at 15,315', back 500 strokes late with 200% increase. Undulate up exiting the OA-3 at 14,762', entered the OA-1 at 14,913'
and leveled out. Began seeing dynamic losses of 80-130 BPH at 15,150'. Reduced flow rate to 480 GPM. Drill 8-1/2" lateral from 15,407' to 16,266' (4,073' TVD).
Drilled 859' = 143.2'/hr AROP. 500 GPM = 2,190 psi, 120 RPM = 18K ft-lbs TQ, WOB = 15K. PU = 175K, SO = 0K & ROT = 111K. MW = 9.1 ppg, Vis = 39, ECD
= 11.4 ppg, max gas = 662 units. MPD choke full open while drilling and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at 15,980', back 600 strokes
late with 100% increase. Begin undulating down at 15,605' exiting the OA-1 at 15,855', entering the OA-3 at 16,160' and level out. Losses slowed to 21 BPH by
15,650'. Drill 8-1/2" lateral from 16,266' to 16,837' (4,088' TVD). Drilled 571' = 95.2'/hr AROP. 490 GPM = 2,310 psi, 120 RPM = 20K ft-lbs TQ, WOB = 8-18K. PU
= 175K, SO = 0K & ROT = 110K. MW = 9.1 ppg, Vis = 40, ECD = 11.6 ppg, max gas = 734 units. MPD choke full open while drilling and trapping 9.3 EMW on
connections. Pump 30 bbl hi-vis sweep at 16,647', back 400 strokes late with 100% increase. Loss rate = 16 BPH. Encountered fault #6 at 16,420' with 10' DTN
throw moving the wellbore from the OA-3 to the OA-2. Encountered fault #7 at 16,560' with 19' DTN throw moving the wellbore from the OA-2 to the NF clays.
Reacquired the OA-1 at 16,715'. Drill 8-1/2" lateral from 16,837' to 17,694' (4,102' TVD). Drilled 857' = 142.8'/hr AROP. 502 GPM = 2,410 psi, 120 RPM = 19K ft-
lbs TQ, WOB = 13-15K. PU = 180K, SO = 0K & ROT = 106K. MW = 9.1 ppg, Vis = 40, ECD = 11.74 ppg, max gas = 861 units. MPD choke full open while drilling
and trapping 9.3 EMW on connections. Pump 30 bbl hi-vis sweep at 17,216', back 200 strokes late with 200% increase. Begin undulating down at 17,280' and
exited the OA-1 at 17,504'. Drilled 51 concretions for a total thickness of 327' (3.2% of the lateral). Distance from WP10 at survey depth of 17,337,81' = 53.25'
(20.57' high & 53.60' right).
9/26/2023 Drill 8-1/2" lateral from 17,694' to 18,358' (4,137' TVD). Drilled 664' = 110.7'/hr AROP. 503 GPM = 2,560 psi, 120 RPM = 20K ft-lbs TQ, WOB = 10-15K. PU =
178K, SO = 0K & ROT = 105K. MW = 9.2 ppg, Vis = 40, ECD = 11.95 ppg, max gas = 660 units. MPD choke full open while drilling and trapping 9.3 EMW on
connections. Pump 30 bbl sweep at 17,787', back 600 strokes late with 100% increase. Pump 30 bbl sweep at 18,263', back 400 strokes late with 70% increase.
Entered the OA-3 18,090'. Encountered fault #8 at 18,244' with 30' DTN throw moving the wellbore form the OA-3 to NF clays. Reacquired the OA-1 at 18,340'. Drill
8-1/2" lateral from 18,357' to 18,931' (4,163' TVD). Drilled 574' = 95.7'/hr AROP. 494 GPM = 2,370 psi, 120 RPM = 22K ft-lbs TQ, WOB = 15K. PU = 193K, SO =
0K & ROT = 107K. MW = 9.0 ppg, Vis = 38, ECD = 11.70 ppg, max gas = 668 units. MPD choke full open while drilling and trapping 9.3 EMW on connections.
Perform 380 bbl dump and dilute at 18,550'. Exited the OA-1 at 18,560' and entered the OA-3 at 18,667'. Encountered fault #9 at 18,870' with 28' DTN throw
moving the wellbore form the OA-3 to NF clays. Drill 8-1/2" lateral from 18,931' to 19,551' (4,181' TVD). Drilled 620' = 103.3'/hr AROP. 490 GPM = 2,500 psi, 120
RPM = 23K ft-lbs TQ, WOB = 10-20K. PU = 218K, SO = 0K & ROT = 115K. MW = 9.2 ppg, Vis = 38, ECD = 11.70 ppg, max gas = 723 units. MPD choke full open
while drilling and trapping 9.3 EMW on connections. Pump 30 bbl sweep at 19,023', back 400 strokes late with 200% increase. Reacquired the OA-1 at 19,030'.
Exited the OA-1 at 19,200' and entered the OA-3 at 19,320'. Drill 8-1/2" lateral from 19,551' to TD at 19,831' (4,183' TVD). Drilled 280' = 112'/hr AROP. 481 GPM =
2,410 psi, 120 RPM = 24K ft-lbs TQ, WOB = 15K. PU = 215K, SO = 0K & ROT = 120K. MW = 9.0+ ppg, Vis = 38, ECD = 11.64 ppg, max gas = 911 units. MPD
choke full open while drilling and trapping 9.3 EMW on connections. Exited the OA-3 into the OA-2 at 19,710'. Obtain final survey at TD. Last survey at 19,831.0'
MD / 4,183.07' TVD, 87.58 deg INC, 1.67 deg AZM. Distance from WP10 at TD = 3.58' (3.41' low & 1.07' left). Drilled 68 concretions for a total thickness of 541
(3.6% of the lateral). Pump 30 bbl hi-vis sweep, 500 strokes late with 100% increase. Circulate 2 of the 3 BU, reciprocating 90' and racking back a stand ever BU at
500 GPM = 2,340 psi, 120 RPM = 24K ft-lbs TQ, MW = 9.0+ ppg, Vis = 38, ECD = 11.64 ppg, max gas = 781 units.
9/27/2023 Finish circulating hole clean with a total of 3x bottoms up at 500 GPM = 2340 psi, 120 RPM = 24K ft-lbs Tq. Rack back a stand every bottoms up to 19487'. RIH f/
19487' t/ 19831'. 500 GPM = 2330 psi, 120 RPM = 20k Tq. Pump 30 bbls high vis spacer, 25 bbls 8.45 ppg vis brine, 30 bbls SAPP pill #1, 25 bbls brine, 30 bbls
SAPP pill #2, 25 bbls brine, 30 bbls SAPP pill #3 then 30 bbls high vis spacer. Displace with 1330 bbls of 8.45 ppg viscosified brine with 3% lubes (1.5% 776 and
1.5% LoTorq). 280 GPM = 1115 psi (ICP), 100 RPM = 21K ft-lbs Tq & 280 GPM = 1130 psi (FCP), 120 RPM = 19K ft-lbs Tq. Shut down the pumps with clean
8.45 ppg viscosified brine to surface. 32 bbl losses during displacement. Monitor the wellbore pressure with MPD choke with no pressure build observed. SimOps:
Clean pit #3. BROOH from 19831' to 15885' pulling 5-10 minutes/stand slowing as needed to clean up tight spots. Rack HWDP in Derrick then laying down DP in
the mouse hole. 450 GPM = 1300 psi, 120 RPM = 23 ft-lbs Tq, Max gas = 1081 units. PU = 182K, SO = none, ROT = 120K. Loss rate = 30-25 BPH. Lowered the
flow rate from 500 GPM to 450 GPM to manage losses. BROOH from 15885' to 12931' pulling 5-10 minutes/stand slowing as needed to clean up tight spots.
Laying down DP in the mouse hole. 450 GPM = 1510 psi, 120 RPM = 17 ft-lbs Tq, Max gas = 108 units. PU = 170K, SO = 75K, ROT = 110K. Loss rate = 26-15
BPH.
9/28/2023 BROOH from 12931' to 10074' pulling 5-10 minutes/stand slowing as needed to clean up tight spots. Laying down DP in the mouse hole. 450 GPM = 1420 psi, 120
RPM = 9 ft-lbs Tq, max gas = 12 units. PU = 170K, SO = 75K & ROT = 110K. Loss rate = 10-25 BPH. BROOH from 10074' to 8295' pulling 5-10 minutes/stand
slowing as needed to clean up tight spots. Laying down DP in the mouse hole. 420 GPM = 1220 psi, 120 RPM = 8 ft-lbs Tq, max gas = 87 units. PU = 145K, SO =
90K & ROT = 110K. Loss rate = 10-20 BPH. BROOH from 8295' to 7249' pulling 5-10 minutes/stand slowing as needed to clean up tight spots. Laying down DP in
the mouse hole. 420-400 GPM = 1150-1000 psi, 120 RPM = 8 ft-lbs Tq, max gas = 117 units. PU = 135K, SO = 96K & ROT = 114K. Loss rate = 5-60 BPH.
Experience packing off at 7680', 250 psi pressure increase and 11.44 ECD spike. Losses increase from 5 BPH to 50-60 BPH. Slow rotary to 30 RPM while pulling
into the shoe from 7249' to 7125' at 420-400 GPM = 1150-1000 psi observing 10K drag. Lost 523 bbls while BROOH. Pump 30 bbl hi-vis sweep at 450 GPM =
1100 psi, 120 RPM = 5K ft-lbs Tq reciprocating 90' and circulate the casing clean with 2 BU. Sweep back on time with 20% increase. MW in/out = 8.9 ppg. Losses
slowing to 10 BPH. Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 28, 19, 11, & 7 psi. EMW = 8.94 ppg. Weight up the surface system to
9.1 ppg. Circulate 9.1 ppg while weighting up the returns on the fly to 9.1 ppg at 6 BPM = 600 psi, 50 RPM = 5K ft-lbs Tq reciprocating 90'. Good 9.1 ppg in/out.
Monitor Well. Initial 10 BPH returns, dropping to 0.5 BPH in 20 min, becoming a trickle in 30 min.
9/29/2023 Continue monitor well for flow through the 2" valve on the MPD head and observe the flow slowing and become static. SimOps: Hold PJSM for removing RCD
bearing. Remove the RCD and install the MPD riser. Well on a slight vac. PJSM, Slip and cut 165' Drilling Line. Calibrate block height, Perform weekly Derrick
inspection. Drop 2.45" OD drift on 100' of wire. POOH 5 stds from 7125' to 6652', hole take 1 bbl over calc fill. Pump dry job and continue trip out of hole from 6652'
to 5605', racking stands in Derrick. PU = 135k, SO = 117k. Trip out of the hole from 5605' to 307' racking back 72 total stands 5 DP. Perform flow check, fluid level
dropping. LD HWDP, jars and NMDCs from 307' to 83'. Read MWD tools. L/D BHA. Bit graded: 1-2-CT-A-X-1-NO-TD. Clear BHA components and clean the rig
floor. Lost 41 bbls on trip out. Clear & Clean Rig Floor. Blow down Geo-Skid. Remove split bushings and install master bushings. Mobilize casing equipment,
centralizers, crossovers to the rig floor. R/U Doyon double stack tongs and elevators. M/U crossover to FOSV. Static loss rate = 4 BPH. P/U, M/U & RIH with round
nose float shoe and crossover joint on 4-1/2",13.5#, L-80, H625 slotted liner per tally to 2288'. Tq to Optimum @ 9,600 ft-lbs with Doyon double stack tongs. PU =
64k, SO = 62k. Loss rate @ 5 BPH. Continue M/U & RIH with 4-1/2", 13.5#, L-80, H625 slotted liner per tally from 2288' to 8107'. Tq to Optimum @ 9,600 ft-lbs
with Doyon double stack tongs. PU = 100k, SO = 75k. Loss rate @ 5 BPH.
9/30/2023 RIH with 4-1/2", 13.5#, L-80, H625 slotted liner per tally from 8107' to 9863'. Tq to Optimum @ 9,600 ft-lbs with Doyon double stack tongs. PU = 105k, SO = 75k.
Loss rate @ 5 BPH. Change tong heads, slips and elevators to 5-1/2". M/U FOSV & handling pup to safety joint. RIH with 5-1/2", 17#, L-80, JFE Bear slotted liner
per tally installing a centralizer on every joint from 9863' to 12908'. Tq to Optimum @ 7400 ft-lbs with Doyon double stack tongs. PU = 125k, SO = 68k. Lost 79 bbls
total while running liner. Swap elevators. M/U Baker SLZXP liner top packer & fill with PAL Mix. RIH one stand to 13038'. Pump 5 bbls through LTP to ensure clear
flow path, 1 BPM = 90 psi. PU = 130k, SO = 70k, ROT = 100k, 10 RPM = 5k and 20 RPM = 7k ft/lbs Tq. Blow down top drive. Remove FOSV from safety jt. TIH
with 4-1/2" x 5-1/2" slotted liner on 5" drill pipe from 13038' to 19831', tagged bottom on depth with 10K. P/U = 190K & SO = 70K. Lost 20 bbls on TIH. Drop 1.125"
phenolic setting ball. M/U TD to string & place liner in tension at 19831' set depth with 190K. Pump ball down with 30 bbl high vis sweep at 3 BPM = 550 psi. Ball
on seat at 1190 strokes. Pressure up and set at 2100 psi and hold for 5 minutes. Set down to confirm set. Pressure up, observe neutralize at 3120 psi & blow ball
seat at 4030 psi. PU & observe travel @ 135K to confirm release. P/U 5' exposing dog sub, S/O with 105k down Wt then set 55k on dogs, P/U to neutral & engage
rotary at 20 RPM6k Tq. Set down 60k on dogs. P/U to neutral. Top of liner at 6896'. Purge lines. Close UPR & pressure test liner top to 1580 psi for 10 minutes on
chart - good test. R/D test equipment. Pump 2.4 bbls / bled back 2.4 bbls. Pump out of the LTP at 2 BPM = 350 psi. Increase to 10 BPM when pressure drop and
returns observed. Lay down 2 jts DP. Continue CBU at 500 GPM = 1500 psi. Sweep back on time with 0% increase. Monitor Well - Slight flow, slowing to static in
45 min then slight losses. SimOps: Clear and clean rig floor. Mobilize thread protectors to rig floor and prep pipeshed for laying down pipe. Pump dry job and blow
down the Top Drive. POOH laying down 5" DP from 6874' to 2440'. PU = 85k, SO = 80k. Loss rate = 4-5 BPH.
Activity Date Ops Summary
10/1/2023 Continue to POOH laying down 5" drill pipe from 2440' to 30'. L/D Baker liner running tool. Lost 20 bbls while POOH - 2 BPH avg. *** Provided 24 hour pre-
injection MIT-IA notification to the AOGCC at 06:30, inspector McLeod waived right to witness at 07:19 ***,RIH with 8 stands 5 HWDP from Derrick and POOH
laying down singles. Remove wear bushings, M/U stack washing tool, flush BOP stack and L/D stack washing tool. Blow down Top Drive. Mobilize Centrilift
equipment to the rig floor. Mobilize & R/U Doyon casing equipment. Make up XO's to FOSV. 2 BPH static losses. MU Baker 7" bullet seal assembly to 22'. RIH with
3-1/2", 9.3#, L-80 EUE 8rd tubing from 22' to 711'. Torque to 3130 ft/lbs optimum torque with Doyon double stack tongs. Loss rate = 2 BPH,MU XN assembly,
tubing joint, Baker Zenth gauge assembly, tubing joint and Viking sliding sleeve assembly spooling TEC wire and installing cannon clamps per tally to 840'. Torque
to 3130 ft-lbs optimum torque with Doyon double stack tongs. PU = 49K & SO = 49K,RIH with 3-1/2", 9.3#, L-80 EUE 8rd tubing spooling TEC wire and installing
cannon clamps per tally from 840 to no-go at 6922.06' (bottom of mule shoe) with 10K down. Torque to 3130 ft-lbs optimum torque with Doyon double stack tongs.
Check TEC wire continuity every 1000'. PU = 80K & SO = 67K. Liner top at 6912.48', 16.48 deep of lower completion tally. Lost 27 bbls while running tubing.
Average loss rate = 2 BPH,Close annular and pressure up 400 psi verifying seals engaged. Lay down joints #219-216. M/U 2.10', 8.19' & 10.23' pup joints. MU
joint #216. R/U circulating equipment on 3-1/2" TC-II landing joint to reverse circulate. M/U tubing hanger & landing jt. Terminate the TEC and feed through the
tubing hanger. Land tubing on hanger at 6920' with locator sub 2.06' of no-go. Centrilift readings: Tubing = 1772.5 psi & 75.9 deg, Annulus = 0.0 psi & 32.0, 20.2
volts.
10/2/2023 Finish R/U to reverse circulate down the IA and taking returns out tubing. Purge and test lines to 2000 psi, good. Close bag, apply 400 psi on annulus, strip up 7
though bag to expose ports on the seal assembly with no confirmation of pressure drop. Check line ups and measurements, bleed pressure, strip bag to landing and
open annular. P/U 7.2 and observe fluid level drop indicating circulating port exposed. Close annular and reverse circulate 459 bbls of 8.4 ppg corrosion inhibited
source water down 3-1/2x9-5/8 annulus at 4 BPM = 660 psi ICP, 840 psi FCP. Strip down through annular, closing circulating ports. Drain stack & blow down lines,
open annular and land tubing on hanger with 37k on hanger. RILDS. Rig up and PT the IA to 3,500 psi for 30 minutes charted - good test. 6.7 bbls pumped, 6.7
bbls bled back. Blow down lines. Clean out drip pan under rig floor. Monitor Well breath back until static. SimOps: Start clean and organize rig in prep for move,Rig
down circulating and test equipment, breakout XOs and lay down the landing joint. WHR install the BPV with dry rod. Pull the MPD riser and 90' mousehole.
Remove the drip pan, turn buckles and kill line. N/D the BOP stack & set on transport pedestal. Install the CTS plug in the BPV. Take rig off hi line @ 15:48 and put
on gen power. Nipple up adapter flange and Tree. Test Hanger void to 500/5000 5/10 min - Good. Rig up test equipment. Fill the Tree with diesel. PT the Tree to
500/5,000 psi (good test). Pull the CTS plug and BPV. Final tubing & annulus pressure = 0 psi. Centrilift final reading - Pt = 1630.8 psi, Tt = 32 degF, Vt = 20.3v.
SimOps: Clean Rockwasher, prep mud pits and Rig down service shacks. Rig welder cut off the mouse hole and seal weld the bottom of the cellar box. Prep to skid
floor into moving position. SimOps: Move support buildings. Blow down rig floor steam/water. Rig released 24:00.
Well Name:
Field:
County/State:
MP I-32
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23759-00-00API #:
ACTIVITYDATE SUMMARY
10/2/2023
WELLHEAD: Completion, MU tbg hgr to LJ and to comp string. Cut 8' and term. 1/4"
tech line through bottom of hgr. Five ft hgr into profile 32.40', RIG test and reverse
ciurculate. RILDS and set 3" CTS Bpv. RIG ND and set back BOP, clean void, install
CTS plug, new RX54, and SBMS metal seal. PU tree/adapter and run tech wire
through adapter, torque to spec. Test 500/5000 5/10 min. (PASS). RIG test tree
(PASS), pull CTS plug and Bpv with dry rod (WELL ON VAC). Dump SSV, close all
valves and install manifold on IA.
10/2/2023
***CHANGE OUT TOOL STRING & GET TOOLS READY FOR MPI-32 RIG JOB***
***CONTINUE WSR ON 10-3-23***
10/3/2023
***CONTINUE WSR FROM 10-2-23***
OPEN SLEEVE @ 6082' SLM / 6094' MD
SET 3'' JET PUMP (ser# MO-1132, ratio: 14C, screen, oal= 88'') SET IN VIKING SS
@ 6082' SLM / 6094' MD
***WELL S/I ON DEPARTURE***
10/3/2023
Well Support techs set foundation, R/U power fluid line, test and prodcuton lines
(hard line) and set well house. Pressure tested production lines to 1150 psi and
power fluild lines to 3650 psi. R/U for flowback to start 30 day flowback.
11/4/2023
T/I/O=700/0 Freeze Protect (Post Flowback) Pumped 146 bbls of 60/40 down IA
and 10 bbls 60/40 down TBG. Final Whps=200/540
11/14/2023
Well Support techs R/D temp hardline for the 30 day producer and installed
permenanet injection piping. Pressure tested injection piping to 3650 psi.
11/28/2023
*** WELL S/I ON ARRIVAL ***
PULL 2.81" X-LOCK, JET PUMP W/ SCREEN FROM VIKING SLEEVE @ 6,090' MD
CLOSE VIKING SLD SLV @ 6,090' MD
*** WELL S/I ON DEPARTURE, DSO NOTIFIED OF STATUS ***
11/28/2023
T/I = 585/22 Load and Test IA, Pumped 250 bbls Inhibited 1% KCL down IA,
PUmped 125 bbls Diesel down IA for Freeze Protect, Pumped 18 bbls 60/40 down IA
to presure up for MIT-IA, No Test, Let well settle over night, FWP = 611/245
11/29/2023
T/I = 590/0 MIT-IA 2000 psi, **Passed** 4.56 bbls diesel to pressure up, 15 min ia
lost 42 psi, 30 min ia lost 18 psi, 3.85 bbls recovered, FWP = 592/200
Daily Report of Well Operations
PBU MPI-32
Daily Report of Well Operations
PBU MPI-32
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
112
1
1
1
60
1
Yes X No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe
Cut Joint
Doyon 14 RKB
10 3/4
482 22.36393.93
SE
C
O
N
D
S
T
A
G
E
Rig
22:50
Cement to surface
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 7178.72 FC @ Top of Liner7,097.52
Floats Held
444.43 795.5
263 532.5
Spud Mud
CASING RECORD
County State Alaska Supv.D. Yessak / J. Gruenberg / I. Toomey
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP I-32 Date Run 17-Sep-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TXP-BTC Innovex 1.58 7,178.72 7,177.14
35.66 68.43 32.77
32.7732.77
9 5/8 47.0 L-80 TXP-BTC
Csg Wt. On Hook:300 Type Float Collar:Innovex No. Hrs to Run:22
9.4 7
1470
10
10.7 377.5 6.5
97.65
750
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
600
3
9.4 6 173/171.1
532/531
1300
30
Rig
15.8 82
Bump press
Cement to surface
Bump Plug?
Yes
6:18 9/19/2023 2,356
2356.01
7,178.727,217.00
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
Tuned Spacer
736 2.85
Stage Collar @
60
Bump press
100
233
HES ES Cemente Closure OK
56
12 280
34.29 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
No. Jts. Delivered No. Jts. Run
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
4
ArcticCem
Type
87 total 9-5/8" x 12-1/4" bow spring centralizers ran. Two in shoe joint w/ stop rings 10' from each end. One floating on
joint #2. One each with stop rings mid-joint on joint #3 & #4. One each on joints #5 to #25, every other joint to #49 then
every third joint to #109. One each on joints #109to #112. One each with stop rings on pup joints above and below ES
cementer. One each on joints #117 to #121 then every third joint #124 to #172.
Casing 9 5/8 40.0 L-80 TXP-BTC Tenaris 78.23 7,177.14 7,098.91
Float Collar 10 3/4 TXP-BTC Innovex 1.39 7,098.91 7,097.52
Casing 9 5/8 40.0 L-80 TXP-BTC Tenaris 42.05 7,097.52 7,055.47
Baffle Adapter 10 3/4 TXP-BTC Halliburton 1.42 7,055.47 7,054.05
Casing 9 5/8 40.0 L-80 TXP-BTC Tenaris 4,680.63 7,054.05 2,373.42
Casing Pup Joint 9 5/8 40.0 L-80 TXP-BTC 14.57 2,373.42 2,358.85
ES Cementer 10 3/4 TXP-BTC Halliburton 2.84 2,358.85 2,356.01
Casing Pup Joint 9 5/8 40.0 L-80 TXP-BTC 14.58 2,356.01 2,341.43
Casing 9 5/8 47.0 L-80 TXP-BTC Tenaris 2,273.00 2,341.43 68.43
EconoCem 669 2.35
HalCem 400 1.16
7.5
HalCem 270 1.17
9/19/2023 Surface
Spud Mud
1
Regg, James B (OGC)
From:Ryan Thompson <Ryan.Thompson@hilcorp.com>
Sent:Thursday, November 9, 2023 12:00 PM
To:Wallace, Chris D (OGC); Regg, James B (OGC); Brooks, Phoebe L (OGC)
Cc:Nathan Sperry
Subject:MIT-IA for MPU I-32 (PTD# 223054)
Attachments:MIT MPU I-32 10-2-23.xlsx
All –
AƩached is the 10‐426 for the passing MIT‐IA performed on rig for MPU I‐32 on 10/2/23.
I apologize for the late submission as this was overlooked aŌer the test compleƟon. The well was on 30 day pre‐
producƟon and has not been placed on injecƟon.
Please let me know if you have any quesƟons.
Thanks,
Ryan Thompson
Milne / Islands Well Integrity Engineer
907‐564‐5005
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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Milne Point Unit I-32PTD 2230540
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-054 Type Inj N Tubing 0 0 0 0 Type Test P
Packer TVD 3904 BBL Pump 6.7 IA 0 3690 3675 3670 Interval O
Test psi 3500 BBL Return 6.7 OA Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Hilcorp Alaska LLC
Milne Point, MPU, I Pad
Brett Anderson
10/02/23
Notes:Pre-Injection MIT-IA on rig. Witness waived by Austin McLeod on 10/1/23 at 7:19 am. Monobore completion, no OA. Test to 3500 psi per PTD.
Notes:
Notes:
Notes:
I-32
Form 10-426 (Revised 01/2017)2023-1002_MIT_MPU_I-32
J. Regg; 3/12/2024
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/13/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU I-32
PTD: 223-054
API: 50-029-23759-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (09/08/2023 to 09/30/2023)
x EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:g
Please include current contact information if different from above.
PTD: 223-054
T38056
10/13/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.10.13
13:48:40 -08'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT I-32
JBR 10/17/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0
The rig just finished yearly maintenance, initial shell test took a little time to fix a hydraulic leak and get the air out of the system.
Once on chart we had zero problems testing. All 4 gas/H2S stations were tested and passed. This is a brand new detection
system. 3.5" & 5" Test joints.
Test Results
TEST DATA
Rig Rep:Jerry Hansen, Cene CveOperator:Hilcorp Alaska, LLC Operator Rep:Ian Toomey, Brett Anderson
Rig Owner/Rig No.:Doyon 14 PTD#:2230540 DATE:9/21/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopJDH230920112524
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7
MASP:
1338
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8" 5M P
#1 Rams 1 2 7/8X5" 5M P
#2 Rams 1 Blinds P
#3 Rams 1 2 7/8X5" 5M P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8" 5M P
HCR Valves 2 3 1/8" 5M P
Kill Line Valves 2 3 1/8" 5M P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3050
Pressure After Closure P1600
200 PSI Attained P41
Full Pressure Attained P196
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6-1825
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P19
#1 Rams P9
#2 Rams P9
#3 Rams P9
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9 9 99
9
9
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-32
Hilcorp Alaska, LLC
Permit to Drill Number: 223-054
Surface Location: 2345' FSL, 4010' FEL, Sec. 33, T13N, R10E, UM, AK
Bottomhole Location: 580' FSL, 725' FEL, Sec. 17, T13N ,R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of July 2023. 28
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.28
16:38:40 -06'00'
1a.
Contact Name:Nathan Sperry
Contact Email:nathan.sperry@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8450
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
5
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill
Lateral
1b.Proposed Well Class:Exploratory - Gas
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
Gas Hydrates
Geothermal
Hilcorp Alaska, LLC Bond No. 22224484
11.Well Name and Number:
MPU I-32
TVD:19880'4181'
12. Field/Pool(s):
MD:
ADL 025906, 025517 & 025515
88-004
4a.
Surface:
Top of Productive Horizon:
Total Depth:
2345' FSL, 4010' FEL, Sec. 33, T13N, R10E, UM, AK
1343' FNL, 2191' FWL, Sec. 32, T13N, R10E, UM, AK
Kickoff Depth:450 feet
Maximum Hole Angle: 97 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:1731 1338
17.Deviated wells:16.
Surface: x-y- Zone -551360 6009459 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
66.9'
33.2'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
2012'
3919'
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
55
Commission Use Only
See cover letter for other
requirements:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
129.5#
50-
Intermediate
Conductor/Structural
Single Zone
Service - Disp
5
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
580' FSL, 725' FEL, Sec. 17, T13N ,R10E, UM, AK
Time v. Depth Plot555 5Drilling Program
3937'
Stg 2 L - 673 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
5-1/2"
x4-1/2"
9-5/8"
4181'
12-1/4"
19880'Uncemented Drilled or
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket 5 Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9.Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
7659
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
8-1/2"
9-5/8" 47#
40#
17#/13.5#
L-80
L-80
L-80 TXP
TXP
JFE Bear
/Hyd 625
2500'
4676'
12854'
Surface
2500'
7026'
2500'
7176'
2012'
3935'
Stg 1 L - 637 sx / T - 395 sx
Slotted Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
135'135'Driven 20"X-52 135'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
MILNE POINT FIELD
SCHRADER BLUFF OIL POOL
3937'
609'
August 20, 2023
6.20.2023
By Grace Christianson at 8:53 am, Jun 20, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.06.20 06:48:09 -08'00'
Monty M
Myers
DSR06/21/23
029-23759-00-00
MGR20JULY2023
* BOPE test to 3000 psi. Annular to 2500 psi.
ADD 26JUL2023
223-054
* Approved for 30 days of preproduction.
1338
* MIT-IA to 3500 psi. 24 hour notice to AOGCC for opportunity
to witness.
* AOGCC to witness MIT-IA after 7 days of stabilized
injection.
* Variance to 200' packer placement above the top of perforations approved.
GCW 07/27/2023
07/28/23
07/28/23
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.07.28 16:39:07 -06'00'
Planned TD
of I-32
Future I-31 producer
(not drilled yet)
Future I-33 producer
(not drilled yet)
I-32 AOR MAP
•All Wells that penetrate the Schrader Bluff Oa labelled at top Oa
intersection point
•Wells that did notpenetrate the Schrader BluffOa are labelled at TD
(Nb is ~140’ TVD shallower than Oa)
•Green lines representthe footageinwells that arewithin the Schrader
Bluff Oainsidethe ¼ mile radiusofproposedinjector,I-32
•Nb wells (abovetarget zone)andObawells (below targetzone)shown
on mapbut not highlighted so it is less busy-included on AOR
spreadsheet
Planned I-32 Top
Schrader Bluff Oa
intersection point
Superseded: map
updated from
operator to include
L-46 and L-47 wells.
-A.Dewhurst
PTD API WELL STATUSTop of SBOA (MD)Top of SBOA (TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD) Schrader OA statusZonal Isolation204-119 50-029-23214-00-00 MPU I-14 Oba Lateral7334 3930 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%washout, TOC is 4242' MD.Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1 bbls15.8ppg class G cement through cement retainer.204-120 50-029-23214-60-00 MPU I-14L1 OA Lateral7334 3930 N/A N/A ClosedReservoir abandoned on 10/13/2020 via coil cement job. Pumped 45 bbls15.8ppg class G through cement retainer.204-121 50-029-23214-61-00 MPU I-14L2 NB Prod LateralN/A N/A N/A N/A N/AAnnulus isolated via 7-5/8" cement job.Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top ofretainer to 6,500' MD.204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral4845 3892 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral4844 3892 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-100 50-029-23212-61-00 MPU I-17L2 OA Lateral4842 3892 N/A N/A Open9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral 5268 3967 3105 2624 Closed9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%washout, TOC is 5154' MD.Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,milled cement to 5582' MD.204-066 50-029-23205-60-00 MPU J-26L1** OBa Lateral 5268 3967 3105 2624 N/A Lateral isolated via iso sleeve and NB/OA reservoir abandonments.204-067 50-029-23205-61-00 MPU J-26L2** OA Lateral 5266 3967 3105 2624 OpenOA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class Gcement. Washed to 5,100' MD.197-215 50-029-22832-00-00 MPU J-20 Schrader, P&A'd for J-20A 7611 3796 N/A N/A ClosedJ-20 was abandoned via the J-20A sidetrack. J-20 was cemented to surfacevia a 2 stage cement job with 84 bbls returned to surface on 12/2/1997.197-208 50-029-22828-00-00 MPU J-17 SB Injector, Shut In 6177 3846 Surface surface OpenWell open to injection support in the NB, NC, OA and OB sands. Packersisolate the NB/NC from the OA/OB.195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6454 4008 3693 2860 ClosedBalanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and4290' MD to 3600' MD.204-073 50-029-23207-00-00 MPU J-25 P&A'd Lateral 4752 3888 2497 2472 ClosedCoil pumped 108 bbls of cmt in NB lateral on July 3, 2020. Cement tagged at3,887' SLMD on 7/13/2020.194-101 50-029-22495-00-00 MPU J-09 P&A'd / Sidetracked 5676 4045 N/A N/A Closed7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washoutestimated at 4,595' MD.Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/ 30min, AOGCC approval to sidetrack well. J-09 P&A'd199-114 50-029-22495-01-00 MPU J-09A OA Producer 6014 4040 N/A N/A Open97sks of cement pumped with bonzai completion, packer depth 5,199',cement valve 6,013'.Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppgclass G. Tagged TOC at 5,237' CTMD.Area of Review MPU I-32 SB OASuperseded: AOR table
updated by operator to
include L-46 and L-47 wells.
-A.Dewhurst
199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5506 4041 4714 3808 ClosedCement valve at 5,776' MD, pump 15 bbls, returns observed on BU TOC atTOL @ 4,714' MD.204-136 50-029-23218-60-00 MPU I-19L1 Suspended OA Lateral7177 4010 3334 2680 Closed Suspended199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6769 4083 N/A N/A Closed Abandoned. Full P&A performed in September/October 2020.197-220 50-029-22834-00-00 MPU J-18 SB Injector Shut In 7404 3907 Surface surfaceOpen**NB, OA, Ob sands open.220-057 50-029-23684-00-00 MPU I-38 NB Producer N/A N/A N/A N/A N/ANot Open220-060 50-029-23686-00-00 MPU I-39 NB Injector N/A N/A N/A N/A N/ANot Open220-071 50-029-23689-00-00 MPU I-40Nb ProducerN/A N/A N/A N/A N/ANot OpenTBD TBD MPU I-31 OA Producer TBD TBD TBD TBD Will be openNot DrilledTBD TBD MPU I-33 OA Producer TBD TBD TBD TBD Will be openNot Drilledsee comment
above
Milne Point Unit
(MPU) I-32
Application for Permit to Drill
Version 1
6/15/2023
Superseded: page
updated by operator to
Version 2.
-A.Dewhurst
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP N/U and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ...................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 39
18.0 RDMO ...................................................................................................................................... 40
19.0 Post-Rig Work ......................................................................................................................... 41
20.0 Doyon 14 Diverter Schematic .................................................................................................. 42
21.0 Doyon 14 BOP Schematic ........................................................................................................ 43
22.0 Wellhead Schematic ................................................................................................................. 44
23.0 Days Vs Depth .......................................................................................................................... 45
24.0 Formation Tops & Information............................................................................................... 46
25.0 Anticipated Drilling Hazards .................................................................................................. 47
26.0 Doyon 14 Layout ...................................................................................................................... 51
27.0 FIT Procedure .......................................................................................................................... 52
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 53
29.0 Casing Design ........................................................................................................................... 54
30.0 8-1/2” Hole Section MASP ....................................................................................................... 55
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 57
Page 2
Milne Point Unit
I-32 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU I-32
Pad Milne Point “I” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Oa Sand
Planned Well TD, MD / TVD 19,880’ MD / 4,181’ TVD
PBTD, MD / TVD 19,880’ MD / 4,181’ TVD
Surface Location (Governmental) 2345' FSL, 4010’ FEL, Sec. 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551360 Y= 6009459
Top of Productive Horizon
(Governmental)1343' FNL, 2191' FWL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 546988 Y= 6011021
BHL (Governmental) 580' FSL, 725' FEL, Sec 17, T13N, R10E, UM, AK
BHL (NAD 27) X= 549232 Y=6023518
AFE Drilling Days 21 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1338 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1731 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 33.2 ft = 66.9 ft
GL Elevation above MSL: 33.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
I-32 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page updated by
operator with I-04
H2S reading.
-A.Dewhurst
Page 4
Milne Point Unit
I-32 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”5-1/2” 4.892”4.767”6.050”17 L-80 JFE Bear 7,740 6,290 397
4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
I-32 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Revised By: JNL 6/15/2022
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU I-32
Last Completed:TBD
PTD:TBD
5-1/2” x 4-1/2” Drilled / Slotted Liner
Top (MD)Top (TVD)Btm (MD)Btm (TVD)
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20"Conductor 129.5 / X-52 / Weld N/A Surface 135’N/A
9-5/8"Surface 47 / L-80 / TXP 8.525”Surface ~2,500’0.0732
9-5/8"Surface 40 / L-80 / TXP 8.679”~2,500’7,176’0.0758
5-1/2”Slotted/Drilled Liner 17 / L-80 / JFE Bear 4.892”7,026 10,026’0.0232
4-1/2”Slotted/Drilled Liner 13.5 / L-80 / Hyd 625 3.920”10,026’19,880’0.0149
TUBING DETAIL
3-1/2"Tubing 9.3 / L-80 / EUE 8RD 2.867”Surface 7,020’0.0087
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4"Stg 1 –Lead637 sx / Tail 395 sx
Stg 2 –Lead 673 sx / Tail 268 sx
8-1/2”Uncemented Drilled / Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K xsliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: TBD
Completion Date: TBD
WELL INCLINATION DETAIL
KOP @ 450’
Max Hole Angle = 97° @ 9,756’ MD
JEWELRY DETAIL
No Top MD Item ID
Upper Completion
1 ~5,950’Zenith Gauge
2 ~6,090’XN Nipple, 2.813”, 2.75” No-Go 2.750”
3 ~7,030’Locater Sub, 8.25” No Go (bottom of locator spaced out 1.70’)6.160”
4 ~7,030’Bullet Seals – TXP Top Box x Mule Shoe 6.160”
Lower Completion
5 7,026’9-5/8” SLZXP Liner Top Packer 6.210”
6 19,933’Shoe
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7.0 Drilling / Completion Summary
MPU I-32 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. I-32 is part of a multi
well re-development program targeting the Schrader Bluff sand on I-Pad. I-32 will be pre-produced for 30
days.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff OA sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the
open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately August 20th, 2023, pending rig schedule.
Surface casing will be run to 7,176’ MD / 3,935’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-32. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for a test period of pre-producing M-63 for up to 30 days via a reverse
circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre-
producing our injectors in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is
online and producing. Section 19 details the steps required to make this happen. Note also that the MIT-IA
has been changed from 2,500 psi to 3,500 psi.
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 I-32 will utilize a newly set 20” conductor on I-Pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until MWD surveys are clean.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, increase in pump pressure, or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
x Gas hydrates have not been seen on I-Pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC:
x I-10 has a 0.852 clearance factor. I-10 was a Schrader well that was abandoned to
surface via cement on September 28, 2013. Collision would likely result in tripping
for a new bit and sidetracking around the abandoned well.
12-1/4” hole mud program summary:
Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid
will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with
a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base
Permafrost
8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate
zone
PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total)
can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
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system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.5 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.6 TOOH and LD BHA
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface
x Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool if the plugs are not bumped.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement is in the Stage 2 table in step 13.22.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.4ppg PP (swabbed kick at 9.5ppg BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 DS50 & NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every stand (confirm frequency with co man)
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x 8-1/2” Lateral A/C:
x I-25 WP04 has a 0.610 CF. This is a planned well and not an actual wellbore.
x J-08A has a 0.703 CF. This is a Schrader OB producer in the same pressure regime. The
risk is primarily financial as a collision would result in a bit trip and open hole sidetrack.
The plan is to geosteer away from J-08A to minimize the collision risk.
x J-09A has a 0.047 CF. This well will has been reservoir P&A’d.
x J-18 has a 0.781 CF. This is a Schrader injector that has been and will be shut-in. The
original Kuparuk completion was abandoned for a Schrader re-complete.
x J-26, 26L1, 26L2, 26PB1, 26PB2 has a 0.293 CF. This multi-lateral has been P&A’d
with cement. There is no HSE risk associated with a collision.
x Schrader Bluff OA Concretions: 4-6% Historically
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
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15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion)
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and
run them slick.
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover
installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner.
x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
x Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 5-1/2” x 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Uppermost 3,000’ will be 5-1/2”.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
outside of the surface shoe. This is to mitigate sticking risk while running inner string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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Drilling Procedure
5-1/2” 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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Drilling Procedure
4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Set below 70 degrees)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
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17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i. Note this test must be witnessed by the AOGCC representative.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
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19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 12B jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
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20.0 Doyon 14 Diverter Schematic
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21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
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22.0 Wellhead Schematic
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23.0 Days Vs Depth
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24.0 Formation Tops & Information
MPU I-32 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1817 1750 2093 799 8.46
SV1 1998 1931 2471 879 8.46
UG4 2295 2228 3093 1010 8.46
UG_MB 3488 3421 5608 1534 8.46
SCHRADER NB 3757 3690 6311 1653 8.46
SCHRADER OA 3927 3860 7091 1728 8.46
I-pad Data Sheet Formation Description
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25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate
gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates,
but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come
out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x I-10 has a 0.852 clearance factor. I-10 was a Schrader well that was abandoned to surface via
cement on September 28, 2013. Collision would likely result in tripping for a new bit and
sidetracking around the abandoned well.
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
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I-32 SB Injector
Drilling Procedure
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Superseded: page updated by
operator to include historical
H2S reading from I-04A well.
-A.Dewhurst
Page 49
Milne Point Unit
I-32 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (5) faults that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
8-1/2” Lateral A/C:
x I-25 WP04 has a 0.610 CF. This is a planned well and not an actual wellbore.
Page 50
Milne Point Unit
I-32 SB Injector
Drilling Procedure
x J-08A has a 0.703 CF. This is a Schrader OB producer in the same pressure regime. The risk is
primarily financial as a collision would result in a bit trip and open hole sidetrack. The plan is to
geosteer away from J-08A to minimize the collision risk.
x J-09A has a 0.047 CF. This well will has been reservoir P&A’d.
x J-18 has a 0.781 CF. This is a Schrader injector that has been and will be shut-in. The original
Kuparuk completion was abandoned for a Schrader re-complete.
x J-26, 26L1, 26L2, 26PB1, 26PB2 has a 0.293 CF. This multi-lateral has been P&A’d with
cement. There is no HSE risk associated with a collision.
Page 51
Milne Point Unit
I-32 SB Injector
Drilling Procedure
26.0 Doyon 14 Layout
Page 52
Milne Point Unit
I-32 SB Injector
Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 53Milne Point Unit I-32 SB InjectorDrillingProcedure28.0 Doyon 14 Choke Manifold Schematic
Page 54
Milne Point Unit
I-32 SB Injector
Drilling Procedure
29.0 Casing Design
Page 55
Milne Point Unit
I-32 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
Page 56
Milne Point Unit
I-32 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Milne Point Unit
I-32 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Built) (NAD 27)
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075015002250300037504500True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 10.00° (1500 usft/in)MPU I-32 wp07 tgt03MPU I-32 wp07 tgt01MPU I-32 wp07 tgt05MPU I-32 wp07 tgt07MPU I-32 wp07 tgt10MPU I-32 wp07 tgt12MPU I-32 wp07 tgt14MPU I-32 wp07 tgt16MPU I-32 wp07 tgt18MPU I-32 wp07 tgt20MPU I-32 wp07 tgt22MPU I-32 wp07 tgt24MPU I-32 wp07 tgt26MPU I-32 wp07 tgt279 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000
850090009500
1 00 0010500110001150012000125001300013500140001450015000155001600016500170001750018000185001900019500
19880MPU I-32 wp08Start Dir 3º/100' : 450' MD, 450'TVDStart Dir 4º/100' : 500' MD, 499.99'TVDStart Dir 3.9º/100' : 1100' MD, 1082.34'TVDEnd Dir : 2141.3' MD, 1840.6' TVDStart Dir 4º/100' : 3465.72' MD, 2472.55'TVDEnd Dir : 3816.44' MD, 2644.77' TVDStart Dir 4.8º/100' : 4866.44' MD, 3169.77'TVDEnd Dir : 5149.53' MD, 3299.33' TVDStart Dir 4.9º/100' : 5759.13' MD, 3549.88'TVDFault #1End Dir : 7001.29' MD, 3915.93' TVDStart Dir 3º/100' : 7091.29' MD, 3926.9'TVDEnd Dir : 7175.29' MD, 3935.36' TVDBegin GeosteeringTotal Depth : 19880.03' MD, 4180.9' TVDSV6Base PermafrostSV1UG4UG_MBSB_NBSB_OAHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU I-32i33.20+N/-S+E/-WNorthingEastingLatitudeLongitude0.000.006009459.02551360.31 70° 26' 11.7408 N 149° 34' 52.4995 WSURVEY PROGRAMDate: 2020-07-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 900.00 MPU I-32 wp08 (MPU I-32i) GYD_Quest GWD900.00 7176.00 MPU I-32 wp08 (MPU I-32i) 3_MWD+IFR2+MS+Sag7176.00 19880.03 MPU I-32 wp08 (MPU I-32i) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation827.90 761.00 831.56 SV61816.90 1750.00 2093.05 Base Permafrost1997.90 1931.00 2470.97 SV12294.90 2228.00 3093.40 UG43487.90 3421.00 5608.33 UG_MB3756.90 3690.00 6310.91 SB_NB3926.90 3860.00 7091.29 SB_OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-32i, True NorthVertical (TVD) Reference:MPU I-32 as built rkb @ 66.90usftMeasured Depth Reference:MPU I-32 as built rkb @ 66.90usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-32iWellbore:MPU I-32iDesign:MPU I-32 wp08CASING DETAILSTVD TVDSS MD SizeName3935.42 3868.52 7176.00 9-5/8 9 5/8" x 12 1/4"4180.90 4114.00 19880.03 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 450.00 0.00 0.00 450.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 450' MD, 450'TVD3 500.00 1.50 200.00 499.99 -0.61 -0.22 3.00 200.00 -0.64 Start Dir 4º/100' : 500' MD, 499.99'TVD4 690.00 9.04 215.08 689.06 -15.19 -9.67 4.00 18.00 -16.635 1100.00 23.40 246.96 1082.34 -73.81 -103.75 4.00 48.00 -90.70 Start Dir 3.9º/100' : 1100' MD, 1082.34'TVD6 2141.30 61.50 270.00 1840.60 -158.30 -780.19 3.90 31.89 -291.37 End Dir : 2141.3' MD, 1840.6' TVD7 3465.72 61.50 270.00 2472.55 -158.30 -1944.12 0.00 0.00 -493.49 Start Dir 4º/100' : 3465.72' MD, 2472.55'TVD8 3816.44 60.00 286.00 2644.77 -116.23 -2245.71 4.00 100.02 -504.43 End Dir : 3816.44' MD, 2644.77' TVD9 4866.44 60.00 286.00 3169.77 134.42 -3119.82 0.00 0.00 -409.38 Start Dir 4.8º/100' : 4866.44' MD, 3169.77'TVD10 5149.53 65.73 299.86 3299.33 232.92 -3350.64 4.80 68.37 -352.45 End Dir : 5149.53' MD, 3299.33' TVD11 5759.13 65.73 299.86 3549.88 509.62 -3832.58 0.00 0.00 -163.65 Start Dir 4.9º/100' : 5759.13' MD, 3549.88'TVD12 7001.29 83.00 1.00 3915.93 1503.13 -4363.76 4.90 84.36 722.53 End Dir : 7001.29' MD, 3915.93' TVD13 7091.29 83.00 1.00 3926.90 1592.44 -4362.20 0.00 0.00 810.76 MPU I-32 wp07 tgt01 Start Dir 3º/100' : 7091.29' MD, 3926.9'TVD14 7175.29 85.43 1.66 3935.36 1675.99 -4360.26 3.00 15.17 893.38 End Dir : 7175.29' MD, 3935.36' TVD15 7285.67 85.43 1.66 3944.15 1785.97 -4357.07 0.00 0.00 1002.2416 7437.17 89.22 1.70 3951.22 1937.21 -4352.63 2.50 0.59 1151.9517 7487.17 89.22 1.70 3951.90 1987.18 -4351.15 0.00 0.00 1201.42 MPU I-32 wp07 tgt0318 7572.08 87.10 1.88 3954.62 2072.01 -4348.50 2.50 175.21 1285.4219 7709.82 87.10 1.88 3961.58 2209.49 -4344.00 0.00 0.00 1421.6020 7908.68 91.77 359.89 3963.53 2408.25 -4340.93 2.55 -23.09 1617.8721 8058.68 91.77 359.89 3958.90 2558.18 -4341.22 0.00 0.00 1765.47 MPU I-32 wp07 tgt0522 8169.54 94.52 0.19 3952.81 2668.87 -4341.14 2.50 6.27 1874.4923 8282.02 94.52 0.19 3943.94 2781.00 -4340.76 0.00 0.00 1984.9824 8455.49 90.50 1.81 3936.34 2954.23 -4337.73 2.50 158.10 2156.1125 8505.49 90.50 1.81 3935.90 3004.20 -4336.15 0.00 0.00 2205.60 MPU I-32 wp07 tgt0726 8879.01 80.27 2.69 3965.93 3375.73 -4321.58 2.75 175.15 2574.0127 8986.74 80.27 2.69 3984.15 3481.79 -4316.60 0.00 0.00 2679.3328 9251.48 86.75 4.02 4014.07 3744.24 -4301.20 2.50 11.62 2940.4629 9301.48 86.75 4.02 4016.90 3794.03 -4297.70 0.00 0.00 2990.10 MPU I-32 wp07 tgt1030 9701.14 96.59 5.78 4005.28 4191.56 -4263.64 2.50 10.12 3387.5131 9880.25 96.59 5.78 3984.74 4368.58 -4245.73 0.00 0.00 3564.9532 10289.03 88.80 12.41 3965.52 4771.24 -4181.20 2.50 139.40 3972.6933 10689.03 88.80 12.41 3973.90 5161.80 -4095.26 0.00 0.00 4372.25 MPU I-32 wp07 tgt1234 10824.10 91.93 13.68 3973.04 5293.36 -4064.78 2.50 22.03 4507.1035 10933.66 91.93 13.68 3969.35 5399.75 -4038.89 0.00 0.00 4616.3736 11108.48 87.83 15.19 3969.72 5569.02 -3995.33 2.50 159.73 4790.6337 11958.48 87.83 15.19 4001.90 6388.73 -3772.77 0.00 0.00 5636.54 MPU I-32 wp07 tgt1438 12159.92 84.62 19.08 4015.17 6580.75 -3713.59 2.50 129.74 5835.9239 12214.45 84.62 19.08 4020.29 6632.07 -3695.84 0.00 0.00 5889.5440 12420.29 88.94 16.28 4031.85 6827.81 -3633.47 2.50 -32.96 6093.1341 13720.29 88.94 16.28 4055.90 8075.47 -3269.10 0.00 0.007385.11 MPU I-32 wp07 tgt1642 13888.88 93.00 17.42 4053.05 8236.76 -3220.24 2.50 15.74 7552.4443 13995.27 93.00 17.42 4047.49 8338.13 -3188.43 0.00 0.00 7657.7944 14172.51 88.87 15.81 4044.60 8507.90 -3137.76 2.50 -158.63 7833.7845 14897.51 88.87 15.81 4058.90 9205.34 -2940.28 0.00 0.00 8554.91 MPU I-32 wp07 tgt1846 15135.25 85.95 20.99 4069.65 9430.60 -2865.35 2.50 119.50 8789.7647 15211.48 85.95 20.99 4075.03 9501.59 -2838.10 0.00 0.00 8864.4148 15386.56 89.29 18.16 4082.30 9666.37 -2779.51 2.50 -40.37 9036.8649 16161.56 89.29 18.16 4091.90 10402.71 -2537.98 0.00 0.00 9803.96 MPU I-32 wp07 tgt2050 16317.09 87.40 15.69 4096.40 10551.42 -2492.73 2.00 -127.53 9958.2651 16459.70 87.40 15.69 4102.88 10688.58 -2454.20 0.00 0.00 10100.0352 16765.66 89.38 9.90 4111.49 10986.68 -2386.50 2.00 -71.18 10405.3653 17265.66 89.38 9.90 4116.90 11479.21 -2300.54 0.00 0.00 10905.33 MPU I-32 wp07 tgt2254 17363.25 91.33 8.43 4116.29 11575.54 -2285.00 2.50 -36.91 11002.8955 17452.81 91.33 8.43 4114.21 11664.10 -2271.86 0.00 0.00 11092.3956 17661.75 86.88 11.17 4117.48 11869.90 -2236.31 2.50 148.44 11301.2357 17926.75 86.88 11.17 4131.90 12129.49 -2185.05 0.00 0.00 11565.79 MPU I-32 wp07 tgt2458 18231.94 85.28 3.69 4152.79 12431.18 -2145.68 2.50 -102.33 11869.7359 18313.51 85.28 3.69 4159.50 12512.31 -2140.45 0.00 0.00 11950.5460 18454.28 88.80 3.78 4166.76 12652.57 -2131.29 2.50 1.44 12090.2661 19129.28 88.80 3.78 4180.90 13325.96 -2086.80 0.00 0.00 12761.14 MPU I-32 wp07 tgt2662 19182.19 90.04 4.23 4181.43 13378.73 -2083.10 2.50 19.87 12813.7563 19880.03 90.04 4.23 4180.90 14074.67 -2031.64 0.00 0.00 13508.05 MPU I-32 wp07 tgt27 Total Depth : 19880.03' MD, 4180.9' TVD
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
12750
13500
14250
South(-)/North(+) (1500 usft/in)-7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000
West(-)/East(+) (1500 usft/in)
MPU I-32 wp07 tgt27
MPU I-32 wp07 tgt26
MPU I-32 wp07 tgt24
MPU I-32 wp07 tgt22
MPU I-32 wp07 tgt20
MPU I-32 wp07 tgt18
MPU I-32 wp07 tgt16
MPU I-32 wp07 tgt14
MPU I-32 wp07 tgt12
MPU I-32 wp07 tgt10
MPU I-32 wp07 tgt07
MPU I-32 wp07 tgt05
MPU I-32 wp07 tgt01
MPU I-32 wp07 tgt03
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
5001
0001500175020002250250027503000325035003 7 5 0
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4181
MPU I-32 wp08
Start Dir 3º/100' : 450' MD, 450'TVD
Start Dir 4º/100' : 500' MD, 499.99'TVD
Start Dir 3.9º/100' : 1100' MD, 1082.34'TVD
End Dir : 2141.3' MD, 1840.6' TVD
Start Dir 4º/100' : 3465.72' MD, 2472.55'TVD
End Dir : 3816.44' MD, 2644.77' TVD
Start Dir 4.8º/100' : 4866.44' MD, 3169.77'TVD
End Dir : 5149.53' MD, 3299.33' TVD
Start Dir 4.9º/100' : 5759.13' MD, 3549.88'TVD
Fault #1
End Dir : 7001.29' MD, 3915.93' TVD
Start Dir 3º/100' : 7091.29' MD, 3926.9'TVD
End Dir : 7175.29' MD, 3935.36' TVD
Begin Geosteering
Total Depth : 19880.03' MD, 4180.9' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3935.42 3868.52 7176.00 9-5/8 9 5/8" x 12 1/4"
4180.90 4114.00 19880.03 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-32i
Wellbore: MPU I-32i
Plan: MPU I-32 wp08
WELL DETAILS: Plan: MPU I-32i
33.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009459.02 551360.31 70° 26' 11.7408 N 149° 34' 52.4995 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-32i, True North
Vertical (TVD) Reference:MPU I-32 as built rkb @ 66.90usft
Measured Depth Reference:MPU I-32 as built rkb @ 66.90usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPU I-25i wp04MPI-10MPI-14L2PB1MPI-14L2MPI-14MPI-13MPU I-31 wp04MPU I-40MPU I-39iMPI-11MPI-12MPI-17L1MPI-17L2No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-32i NAD 1927 (NADCON CONUS)Alaska Zone 0433.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006009459.02551360.3170° 26' 11.7408 N149° 34' 52.4995 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-32i, True NorthVertical (TVD) Reference:MPU I-32 as built rkb @ 66.90usftMeasured Depth Reference:MPU I-32 as built rkb @ 66.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-07-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 900.00 MPU I-32 wp08 (MPU I-32i) GYD_Quest GWD900.00 7176.00 MPU I-32 wp08 (MPU I-32i) 3_MWD+IFR2+MS+Sag7176.00 19880.03 MPU I-32 wp08 (MPU I-32i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPU I-25i wp04MPU I-33 wp09MPI-14MPI-14MPU I-26 wp06MPI-06MPI-13MPU I-31 wp04MPI-08MPU I-40MPU I-38MPU I-39iMPI-04MPI-07MPI-11MPI-12NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 19880.03Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-32iWellbore: MPU I-32iPlan: MPU I-32 wp08Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3935.42 3868.52 7176.00 9-5/8 9 5/8" x 12 1/4"4180.90 4114.00 19880.03 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 15400 16100 16800 17500 18200 18900 19600 20300Measured Depth (1400 usft/in)MPU I-25i wp04MPU I-33 wp09MPI-14L2PB1MPJ-08AMPJ-19MPJ-25MPJ-09AMPJ-26L1MPJ-26PB1MPJ-26MPJ-26PB2MPJ-26L2MPU I-31 wp04MPJ-17MPJ-18MPL-48No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU I-32i NAD 1927 (NADCON CONUS)Alaska Zone 0433.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006009459.02 551360.3170° 26' 11.7408 N149° 34' 52.4995 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-32i, True NorthVertical (TVD) Reference:MPU I-32 as built rkb @ 66.90usftMeasured Depth Reference:MPU I-32 as built rkb @ 66.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-07-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 900.00 MPU I-32 wp08 (MPU I-32i) GYD_Quest GWD900.00 7176.00 MPU I-32 wp08 (MPU I-32i) 3_MWD+IFR2+MS+Sag7176.00 19880.03 MPU I-32 wp08 (MPU I-32i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 15400 16100 16800 17500 18200 18900 19600 20300Measured Depth (1400 usft/in)MPU I-25i wp04MPU I-25i wp04MPU I-25i wp04MPU I-39iNO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 19880.03Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-32iWellbore: MPU I-32iPlan: MPU I-32 wp08Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3935.42 3868.52 7176.00 9-5/8 9 5/8" x 12 1/4"4180.90 4114.00 19880.03 4-1/2 4 1/2" x 8 1/2"
PTD API WELL STATUSTop of SBOA (MD)Top of SBOA (TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD) Schrader OA statusZonal Isolation204-119 50-029-23214-00-00 MPU I-14 Oba Lateral7334 3930 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 750 sx Class G. Assuming 20%washout, TOC is 4242' MD.Reservoir abandoned on 10/13/2020 via coil cement job. Pumped 43.1 bbls15.8ppg class G cement through cement retainer.204-120 50-029-23214-60-00 MPU I-14L1 OA Lateral7334 3930 N/A N/A ClosedReservoir abandoned on 10/13/2020 via coil cement job. Pumped 45 bbls15.8ppg class G through cement retainer.204-121 50-029-23214-61-00 MPU I-14L2 NB Prod LateralN/A N/A N/A N/A N/AAnnulus isolated via 7-5/8" cement job.Reservoir abandoned 10/15/2020 via coil cement job. Pumped 41 bbls of14.0ppg SqueezeCrete through retainer. Left 15.8ppg cement on top ofretainer to 6,500' MD.204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral4845 3892 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral4844 3892 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-100 50-029-23212-61-00 MPU I-17L2 OA Lateral4842 3892 N/A N/A Open9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral 5268 3967 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%washout, TOC is 5154' MD.Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,milled cement to 5582' MD.204-066 50-029-23205-60-00 MPU J-26L1** OBa Lateral 5268 3967 N/A N/A N/A Lateral isolated via iso sleeve and NB/OA reservoir abandonments.204-067 50-029-23205-61-00 MPU J-26L2** OA Lateral 5266 3967 N/A N/A OpenOA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class Gcement. Washed to 5,100' MD.197-215 50-029-22832-00-00 MPU J-20 Schrader, P&A'd for J-20A 7611 3796 N/A N/A ClosedJ-20 was abandoned via the J-20A sidetrack. J-20 was cemented to surfacevia a 2 stage cement job with 84 bbls returned to surface on 12/2/1997.197-208 50-029-22828-00-00 MPU J-17 SB Injector, Shut In 6177 3846 Surface surface OpenWell open to injection support in the NB, NC, OA and OB sands. Packersisolate the NB/NC from the OA/OB.195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6454 4008 3693 2860 ClosedBalanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and4290' MD to 3600' MD.204-073 50-029-23207-00-00 MPU J-25 P&A'd Lateral 4752 3888 2497 2472 ClosedCoil pumped 108 bbls of cmt in NB lateral on July 3, 2020. Cement tagged at3,887' SLMD on 7/13/2020.194-101 50-029-22495-00-00 MPU J-09 P&A'd / Sidetracked 5676 4045 N/A N/A Closed7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washoutestimated at 4,595' MD.Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/ 30min, AOGCC approval to sidetrack well. J-09 P&A'd199-114 50-029-22495-01-00 MPU J-09A OA Producer 6014 4040 N/A N/A Open97sks of cement pumped with bonzai completion, packer depth 5,199',cement valve 6,013'.Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppgclass G. Tagged TOC at 5,237' CTMD.199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5506 4041 4714 3808 ClosedCement valve at 5,776' MD, pump 15 bbls, returns observed on BU TOC atTOL @ 4,714' MD.Area of Review MPU I-32 SB OA
204-136 50-029-23218-60-00 MPU I-19L1 Suspended OA Lateral7177 4010 3334 2680 Closed Suspended199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6769 4083 N/A N/A Closed Abandoned. Full P&A performed in September/October 2020.197-220 50-029-22834-00-00 MPU J-18 SB Injector Shut In 7404 3907 Surface surfaceOpen**NB, OA, Ob sands open.220-057 50-029-23684-00-00 MPU I-38 NB Producer N/A N/A N/A N/A N/ANot Open220-060 50-029-23686-00-00 MPU I-39 NB Injector N/A N/A N/A N/A N/ANot Open220-071 50-029-23689-00-00 MPU I-40Nb ProducerN/A N/A N/A N/A N/ANot OpenTBD TBD MPU I-31 OA Producer TBD TBD TBD TBD Will be openNot DrilledTBD TBD MPU I-33 OA Producer TBD TBD TBD TBD Will be openNot Drilled215-120 50-029-23552-00-00 MPU L-48 OA Injector 6003 3987 Surface Surface OpenLateral in OA215-117 50-029-23550-00-00 MPU L-47 OA Producer 6923 3956 Surface Surface OpenLateral in OA
Milne Point Unit
(MPU) I-32
Application for Permit to Drill
Version 2
7/19/2023
Page 48
Milne Point Unit
I-32 SB Injector
Drilling Procedure
H2S:
Treat every hole section as though it has the potential for H2S. I-04A had 36ppm H2S (2012).
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
I-04A had 36ppm H2S (2012).
1
Dewhurst, Andrew D (OGC)
From:Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent:Wednesday, 26 July, 2023 20:45
To:Dewhurst, Andrew D (OGC)
Cc:Joseph Lastufka; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Rixse, Melvin G (OGC)
Subject:Re: [EXTERNAL] MPU-I-32 (PTD 223-054) - Questions
Andy,
Thatlooksaccuratetome.Iappreciateyourefforttoinsertthosechanges.
Thankyou
OnJul26,2023,at11:36AM,Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>wrote:
Nate,
Thanksforthoseupdates.
Thewayourprocessworks,Iinserttheupdatedchangesintotheoriginalapplication.Pleaseconfirm
thatIamcapturingeverythingfromtheVersion2PTDapplication:
1. AORmap
2. AORtable
3. Applicationcoverpage,nowversion2
4. ManagementofChangethatincludestheH2Sinfo(p.3)
5. H2Sinfopage(p.48)withIͲ04Awell
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservationCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1245
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGas
ConservationCommission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontain
confidentialand/orprivilegedinformation.Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateor
federallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit,and,sothat
theAOGCCisawareofthemistakeinsendingittoyou,contactAndrewDewhurstat907Ͳ793Ͳ1245or
andrew.dewhurst@alaska.gov.
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
2
From:NathanSperry<Nathan.Sperry@hilcorp.com>
Sent:Monday,24July,202310:12
To:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;JosephLastufka
<Joseph.Lastufka@hilcorp.com>
Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)
<meredith.guhl@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>
Subject:RE:[EXTERNAL]MPUͲIͲ32(PTD223Ͳ054)ͲQuestions
Importance:High
Andy,
I’veattachedanupdatedAORmap,updatedAORtable,andanupdatedprogramforMPUIͲ32.
TheupdatedmapandtableincludeMPULͲ47andMPULͲ48.
Iconsultedwiththeoperationsengineerre:theJͲ26discrepancy.Fromwhatwecantell,webelievethe
3105’referenceisamisunderstandingasitreferstothesurfacecasingshoe.Thecementrecordswe
havematchthelanguageinthecommentssection(i.e.278sxpumped).
Regards,
NateSperry
DrillingEngineer
HilcorpAlaska,LLC
O:907Ͳ777Ͳ8450
C:907Ͳ301Ͳ8996
From:Dewhurst,AndrewD(OGC)[mailto:andrew.dewhurst@alaska.gov]
Sent:Wednesday,July19,20233:53PM
To:NathanSperry<Nathan.Sperry@hilcorp.com>;JosephLastufka<Joseph.Lastufka@hilcorp.com>
Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)
<meredith.guhl@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>
Subject:RE:[EXTERNAL]MPUͲIͲ32(PTD223Ͳ054)ͲQuestions
Nate,
Pleasesendanyrevisionstome.Iwillmakesureitgetsprocessedcorrectly.
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservationCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1245
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGas
ConservationCommission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontain
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
confidentialand/orprivilegedinformation.Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateor
federallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit,and,sothat
theAOGCCisawareofthemistakeinsendingittoyou,contactAndrewDewhurstat907Ͳ793Ͳ1245or
andrew.dewhurst@alaska.gov.
From:NathanSperry<Nathan.Sperry@hilcorp.com>
Sent:Wednesday,19July,202315:46
To:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;JosephLastufka
<Joseph.Lastufka@hilcorp.com>
Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)
<meredith.guhl@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>
Subject:RE:[EXTERNAL]MPUͲIͲ32(PTD223Ͳ054)ͲQuestions
Andy,
We’veupdatedtheAORtableandupdatedtheApplicationforPermittoDrilldocument.
Wearestillwaitingonthemapanditmaybeafewdays.
Howwouldyoulikeustogoaboutsubmittingtheupdates?
Thanks,
NateSperry
DrillingEngineer
HilcorpAlaska,LLC
O:907Ͳ777Ͳ8450
C:907Ͳ301Ͳ8996
From:NathanSperry
Sent:Wednesday,July19,20232:36PM
To:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;JosephLastufka
<Joseph.Lastufka@hilcorp.com>
Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)
<meredith.guhl@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>
Subject:RE:[EXTERNAL]MPUͲIͲ32(PTD223Ͳ054)ͲQuestions
Andrew,
Thefolkswhoproducethemaps/handletheAORareoutthisweekbutwewilldoublecheckthosewells
oncethey’reback.Icheckedourdirectionalsoftwareanditlookstomelikeyou’rerightaboutLͲ48but
I’mseeingthatLͲ46isgreaterthan1320’fromIͲ32.Wewilldoublecheckthatinthemapping
software.
WewillupdatetheH2SandtheJͲ26TOC.
I’llworkwithJoeL.toresubmittherequiredinformation.
You don't often get email from nathan.sperry@hilcorp.com. Learn why this is important
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
4
Regards,
NateSperry
DrillingEngineer
HilcorpAlaska,LLC
O:907Ͳ777Ͳ8450
C:907Ͳ301Ͳ8996
From:Dewhurst,AndrewD(OGC)[mailto:andrew.dewhurst@alaska.gov]
Sent:Wednesday,July19,20232:24PM
To:NathanSperry<nathan.sperry@hilcorp.com>
Cc:Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,MeredithD(OGC)
<meredith.guhl@alaska.gov>;Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov>
Subject:[EXTERNAL]MPUͲIͲ32(PTD223Ͳ054)ͲQuestions
Nathan,
InreviewofthePTDfortheIͲ32injector,Ihaveafewquestionsforyou.
1. ItappearsthatthereisanLͲpadOainjector/producerpair(LͲ46andLͲ48)thatentersintothe
quartermileradiusofthisBHL:50Ͳ029Ͳ23551Ͳ00and50Ͳ029Ͳ23552Ͳ00.Iunderstandtheyare
bothundergoingremediation/repair.Wouldyouplease:
1. summarizethecurrentstatusofthesetwowellsandhowtheymaybeimpactedby
injectionfromIͲ32
2. replywithreason(s)toexcludefromtheAOR,otherwise,pleaseaddtomapandlist
providedwithPTDapplication
2. ForSection25(Hazards),pleaseaddreferenceto36ppmH2SobservationatIͲ04A(2012
sample).SeeMPUIͲ29PTDapplication(Permit222Ͳ006)forexample.
3. PleaseexplaindifferenceinreportedTOCforMPUJͲ26summary.Correctifnecessary.
<image001.png>
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservationCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1245
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGas
ConservationCommission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontain
confidentialand/orprivilegedinformation.Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateor
federallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit,and,sothat
theAOGCCisawareofthemistakeinsendingittoyou,contactAndrewDewhurstat907Ͳ793Ͳ1245or
andrew.dewhurst@alaska.gov.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual
or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
MPU I-32
223-054
x
Schrader Bluff OilMilne Point
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT I-32Initial Class/TypeSER / 1WINJGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230540MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes SHL in ADL 0025906; Top productive zone in ADL 0025517; BHL in ADL 00255152 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by 477, 477.0054 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)Yes Asking as variance. MIT-IA change.16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 135'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows multiple close approaches with proper management.26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring will be required.33 Is presence of H2S gas probableYes This well is a WINJ34 Mechanical condition of wells within AOR verified (For service well only)No H2S has been measured in MPU I-04A (36 ppm)35 Permit can be issued w/o hydrogen sulfide measuresYes Offset well data and comments36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate7/26/2023ApprMGRDate7/24/2023ApprADDDate7/26/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 07/27/2023
